# TECHNICAL GUIDELINES

**VOLUNTARY REPORTING OF GREENHOUSE GASES**

**(1605(b)) PROGRAM**

OFFICE OF POLICY AND INTERNATIONAL AFFAIRS

UNITED STATES DEPARTMENT OF ENERGY

JANUARY 2007

TECHNICAL GUIDELINES

VOLUNTARY REPORTING OF GREENHOUSE GASES

(1605(b)) PROGRAM

OFFICE OF POLICY AND INTERNATIONAL AFFAIRS

UNITED STATES DEPARTMENT OF ENERGY

## Table of Contents

[TECHNICAL GUIDELINES i](#technical-guidelines)

[Table of Contents iii](#table-of-contents)

[Chapter 1, Emission Inventories 1](#chapter-1-emission-inventories)

[Part A: Introduction 1](#part-a-introduction)

[Part B: Collecting Information 11](#part-b-collecting-information)

[Part C: Stationary Source Combustion
33](#part-c-stationary-source-combustion)

[Part D: Mobile Sources 57](#part-d-mobile-sources)

[Part E: Industrial Processes 79](#part-e-industrial-processes)

[Part F: Indirect Emissions 145](#part-f-indirect-emissions)

[Part G: Geologic Sequestration 163](#part-g-geologic-sequestration)

[Part H: Agricultural Emissions and Sequestration
179](#part-h-agricultural-emissions-and-sequestration)

[Part I: Forestry Emissions 225](#part-i-forestry-emissions)

[Chapter 2, Emission Reductions 251](#chapter-2-emission-reductions)

[2.1 Introduction 252](#introduction)

[2.2 Calculating Emission Reductions
252](#calculating-emission-reductions)

[2.3 Base Periods and Base Values 261](#base-periods-and-base-values)

[2.4 Technical Guidelines for the Application of Specific Calculation
Methods
267](#technical-guidelines-for-the-application-of-specific-calculation-methods)

[2.5 Determining Registered Emission Reductions
302](#determining-registered-emission-reductions)

[2.6 Revising Previously Accepted Reports of Emission Reductions
302](#revising-previously-accepted-reports-of-emission-reductions)

[Glossary 305](#glossary)

###  {#section .tc1}

## 

**Technical Appendices**

Part H Appendix: Estimating Carbon Fluxes from Agricultural Lands Using
the CarbOn

Management Evaluation Tool for Voluntary Reporting (COMET-VR©)

Part I Appendix: Forestry

Technical Guidelines for Voluntary Reporting of Greenhouse Gases Program

## Chapter 1, Emission Inventories

### Part A: Introduction

Outline

1.  Overview

2.  Purposes and Principles

> 3\. Contents of the Inventory Chapter of the Technical Guidelines

4.  The Emissions Rating System

> 4.1. Summary

4.2. Ratings

4.3. Inventory Weighted Average Rating

4.4. Objectives of the Emissions Rating System

5.  Issues Associated with Activity Reporting for Small Entities

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5.  Covered Gases and Global Warming Potentials

> 6\. Revisions to Emissions Inventory Reports

**Technical Guidelines Chapter 1, Part A: Introduction**

#### 1.A.1 Overview

On February 14, 2002, the President directed the Secretary of Energy, in
consultation with the Secretary of Commerce, the Secretary of
Agriculture, and the Administrator of the Environmental Protection
Agency, to propose improvements to the voluntary emission reduction
registration program under section 1605(b) of the 1992 Energy Policy
Act. The improvements were to enhance measurement accuracy, reliability
and verifiability, working with and taking into account emerging
domestic and international approaches.

In response to this charge, the Department of Energy (DOE), in
consultation with the other agencies, has revised the reporting
Guidelines for the Voluntary Reporting Program in two parts:

-   General Guidelines

-   Technical Guidelines (calculating emissions and reductions)

The purpose of the General Guidelines is to establish the procedures and
requirements for filing voluntary reports. The purpose of the Technical
Guidelines is to define permissible methods of calculating reportable
emissions and reductions. The Technical Guidelines are, in turn, divided
into two chapters:

-   Chapter 1, Greenhouse Gas Emissions Inventory Guidelines

-   Chapter 2, Greenhouse Gas Emission Reductions Guidelines

The Inventory Chapter is intended to be primarily a document in which
possible methods of estimating emissions and sequestration from the
sources most likely to be encountered are reviewed and rated. These
Guidelines have a secondary purpose of acting as a guide for reporters
on how to estimate emissions, complementing the many excellent works
already in the public domain that cover this issue. The Inventory
Chapter therefore avoids a detailed, guidebook-like approach unless the
estimation methods are not in the public domain.

#### 1.A.2 Purposes and Principles

In preparing emissions inventories, reporters will be required to make
many decisions, small and large. The DOE is therefore providing
extensive guidance on how to calculate and report greenhouse gas
emissions. No set of guidelines, however, can provide explicit guidance
on every decision that reporters may confront. While the General and
Technical Guidelines endeavor to provide guidance on the most important
points, there will frequently be another layer of complexity that the
reporter must resolve.

On those occasions when sufficiently explicit guidance is not provided,
reporters should decide how to act based upon achieving the overarching
objective of credibility. Only a report that is broadly held to be
credible will have future utility and achieve the shared objectives of
both the reporter and the DOE. The overarching purpose of the Guidelines
themselves is to define the set of choices that are most likely to
produce a credible report. In defining a credible report, the DOE has
tried to rely on the principles listed below. In making decisions for
themselves, reporters should also rely on these principles.

**Accuracy**. Reports should accurately characterize the emissions of
the reporter. In choosing emissions estimation methods, reporters should
endeavor to use the most accurate method.

Accuracy, however, has another dimension. Resources, both human and
financial, that can be devoted to inventory preparation are inevitably
limited. In deploying limited resources, reporters should emphasize the
emission sources that account for the largest share of total emissions
at the possible expense of minor sources.

**Objectivity**. An emissions inventory should attempt to objectively
and fairly describe the emissions of the reporter. The reporter should
strive to produce a report that is akin to one that would be submitted
by a knowledgeable but disinterested third party, describing the
emissions situation of the reporter, rather than one written by an agent
who puts the most favorable construction on a given set of facts or
selectively chooses those facts that favor a particular interest.

**Completeness**. Reporters should strive to report on all applicable
emissions sources and sequestration within the boundaries of the
reporting entity, subject to the provisions of the General Guidelines.

**Verifiability**. "Verifiability" means that the methods chosen, the
application of the methods, and the data used should be, in principle,
accessible to verification by a third party, whether or not such
verification actually takes place. In part, this implies preservation of
data; in part this means documenting data, methods, and the application
of methods with sufficient transparency; and in part this implies
choosing approaches that can be explained and documented.

**Consistency**. Reporters should be consistent as possible in their
choice of boundary definitions, data estimation and data quality methods
and other entity-determined rules. Consistency has two primary aspects:

-   *Intertemporal Consistency*. Estimation methods should be applied
    consistently over time.

-   *Entity-wide Consistency*. Estimation methods and data quality
    methods should, to the extent possible, be applied consistently in
    different parts of the entity. Rules on inclusion and exclusion of
    sources within the entity\'s boundary should be applied
    consistently, subject to the provisions of the General Guidelines.

#### 1.A.3 Contents of the Inventory Chapter of the Technical Guidelines

The Inventory Chapter of the Technical Guidelines consists of nine
parts, of which this is the first. The contents of the nine parts are
summarized as follows:

**A. Introduction** describes the contents of the Inventory Chapter,
with special reference to specific problems that reporters face in
estimating emissions and sequestration, and describes both the approach
adopted by the Technical Guidelines and the Department's thinking in
adopting this approach.

**B. Collecting Information** provides guidance on entity boundaries and
describes where and how reporters may gather the information necessary
to construct their reports.

**C. Stationary Source Combustion** provides guidance on reporting
greenhouse gas emissions from stationary combustion of fossil fuels.

**D. Mobile Sources** provides guidance on reporting greenhouse gas
emissions from mobile sources. This includes the use of ethanol as a
transportation fuel.

**E. Industrial Processes** provides guidance on a wide range of
industrial process emissions sources, including emissions from mining,
oil and gas production, and several chemical industry processes, and
emissions from landfills and other sources of anaerobic decomposition.

**F. Indirect Emissions** provides guidance on estimating greenhouse gas
emissions from purchases of electricity, steam, and hot or chilled
water.

**G. Geologic Sequestration** provides guidance on the reporting of
engineered carbon dioxide (CO~2~) sequestration, including both enhanced
oil recovery and sequestration of carbon dioxide streams.

**H. Agricultural Emissions and Sequestration**, prepared by the U.S.
Department of Agriculture, provides guidance on estimating greenhouse
gas emissions and soil carbon sequestration from agricultural sources
and sinks (ethanol fuels are covered in Part D, Mobile Sources).

**I. Forestry Emissions and Sequestration,** prepared by the U.S.
Department of Agriculture, provides guidance on estimating forest carbon
sequestration and emissions from forests, woody biomass, and the wood
product sector.

#### 1.A.4 The Emissions Rating System

##### 1.A.4.1 Summary

The President's charge to DOE specified that the Department should
propose reforms to improve the "accuracy, reliability, and
verifiability" of reported emissions. To contribute to achieving this
objective, the revised Guidelines require reporters who wish to register
their reductions to "rate" their data and emissions estimation methods,
and establishes minimum standards for the methods and data used to
calculate reporters' overall emissions. This approach has been adopted
to resolve a number of difficulties associated with adapting emissions
inventory methods to the problem of calculating "entity" emissions and
using such entity estimates to register reductions. In particular, this
approach is intended to make the estimation of registered reductions
more accurate, reliable and verifiable.

The emissions rating system is an *ordinal* rating of emission
estimation methods by sector and emission source. The best available
method, based on the four evaluation criteria of accuracy, reliability,
verifiability and practical application, is usually rated "A," and given
a value of four points. An A rating is restricted to methodologies where
computations are based on a preponderance of values indicative of
on-site conditions over multiple periods. The next best method -- or
best method in those cases where no methodology qualifies for an A
rating - will be rated "B" and given a value of three points; the next
best rated "C" and given a value of two points; and the least accurate
method rated "D" and given a value of 1 point.

Reporters should assign the rating provided by the Technical Guidelines
to each source for each year in which emissions are reported. The
average rating (weighted by emissions) of all reported emissions and
sequestration must be 3.0 or higher in the base period and any year in
which reductions are reported in order for the reductions or
sequestration to qualify as "registered reductions."

##### 1.A.4.2 Ratings

The Technical Guidelines describe numerous methods of estimating
emissions of greenhouse gases. The methods are generally considered in
combination with the information or activity data needed to implement
the method so as to provide the greatest accuracy, reliability,
verifiability and practicality of application. The Technical Guidelines
provide ratings for combinations of methods and information used to
apply the methods.

The rating system is an *ordinal* rating system with four values, A
through D. The rating system is ordinal in the sense that A is
considered "better" than B, B is "better" than C, and C is "better" than
D. The highest rated method is believed by the Department to be the best
method available, based on its evaluation criteria as shown in Table
1.A.1, for a particular emissions source in a given sector. However, two
A-rated methods for different sources may not be comparable. Both will
be the best method available, but in one case the best method available
may be highly accurate, and in another case less so.

There are four possible ratings that may be applied to estimation
methods. Table 1.A.1 provides a general description of the criteria used
to set the four ratings for particular sources within the Technical
Guidelines.

Table 1.A.1. Description of Ratings for Measurement and Estimation
Methods

  ------------ ------------ ----------------------------------------------------------
  **Rating**   **Points**   **Typical Description**

  A            4            Continuous direct measurement (CEM) of actual emissions
                            source; or emissions factor based upon multiple, recent,
                            regularly repeated, on-site, direct measurements of
                            sources, multiplied by measured activity data. Activity
                            data measure the actual relevant activity, rather than an
                            indirect indicator of that activity (for instance, fuel
                            consumption rather than purchases).

  B            3            Emissions factor based on limited direct measurements of
                            source or representative sample multiplied by measured
                            activity data. Activity data measure actual use, rather
                            than purchases (if applicable).

  C            2            Default emissions factor multiplied by measured activity
                            data; or emissions factor based on single measurement
                            multiplied by estimated activity data.

  D            1            Default emissions factor multiplied by estimated activity
                            data or static one-time monitoring.
  ------------ ------------ ----------------------------------------------------------

There will be estimation methods not covered in the Technical Guidelines
for various reasons. For example, the estimation method may not have
been developed at the time the Guidelines were written, the source to
which the method applies may not be included in the Guidelines, the
greenhouse gas may represent a relatively small source such as methane
released from forests or the authors of the Technical Guidelines may be
unaware of the existence of a particular method or source.

Reporters may request DOE approval for the use of estimation methods not
included in the Technical Guidelines if the methods cover sources not
described in the Guidelines, or if the proposed methods provide more
accurate results -- or may be more cost effective -- for the reporter's
specific circumstances than the methods described in the Guidelines. If
a reporter wishes to propose the use of a method that is not described
in the Guidelines, the reporter must submit a description of the method,
an explanation of how the method is implemented (including data
requirements), evidence of the method's validity and accuracy, and a
suggested rating for the method to DOE's Office of Policy and
International Affairs (with a copy to the Energy Information
Administration (EIA)). DOE reserves the right to deny the request, or to
assign its own rating to the method. By submitting this information, the
reporter grants permission to DOE to incorporate it in a future revision
of the Guidelines.

##### 1.A.4.3 Inventory Weighted Average Rating

The reporter shall assign a rating drawn from the Technical Guidelines
to each category of emissions and sequestration. The reporter shall
multiply the points of the rating (drawn from Table 1.A.1 above) by the
share of each category in total emissions and sequestration. The
inventory's average rating is the sum of the reporter's ratings for each
category, weighted by each category's share in total emissions.

For the purposes of calculating an overall weighted average rating, the
reporter shall use the absolute value of sequestration or change in
carbon stock (i.e., sequestration is converted into a positive number
and added to emissions). The reporter shall also convert all emissions
from particular greenhouse gases into carbon dioxide equivalents, using
the 100-year Global Warming Potentials published by the
Intergovernmental Panel on Climate Change.[^1]

The reporter shall calculate an inventory weighted average rating for
each year of emissions reported to the Voluntary Reporting Program. If
the reporter uses the same estimation methods for multiple reporting
years (which would normally be the case), then the rating should remain
relatively stable, baring substantial change in relative emission
quantities from the various sources. If the reporter changes estimation
methods, then the ratings should change to reflect the different
estimation methods in use for each year.

If a reporter is seeking to register reductions, the weighted average
rating for emissions for both the base period and the year used to
calculate such reductions should be greater than or equal to 3.0. The
choice of the value for the weighted average reflects DOE's belief that
methods given an A or B rating are sufficiently accurate to serve as the
basis for entity-wide reporting, while methods given a C or D rating
should be used only for those gases or sources that represent a small
share of the reporting entity's total emissions.

##### 1.A.4.4 Objectives of Emissions Rating System

The emissions rating system is designed to achieve the following
objectives:

-   Help achieve the President's stated objective of improving the
    "accuracy, reliability, and verifiability" of reported emissions.

    -   Ensure that total reported emissions are as accurate as
        possible, given the available estimation methods for the actual
        array of sources.

    -   Create an incentive for reporters to use more accurate methods.

    -   Ensure that the cost of emissions estimation for particular
        sources can be commensurate with each source's importance in a
        reporter's inventory.

    -   Ensure that implementation is practical.

##### 1.A.4.5 Issues Associated with Activity Reporting for Small Emitters

The General Guidelines contain provisions that allow small emitters
(those emitting under 10,000 metric tons carbon dioxide equivalent per
year) to register reductions based on specific activities rather than
comprehensive entity-wide inventories. Small emitters choosing to
register reductions will need to meet other criteria established in the
General Guidelines, including determining the total annual emissions and
sequestration associated with the specific activities, the net emission
changes associated with those activities, and certification that the
changes are not likely to cause emission increases elsewhere in the
entity's operations.

Small emitters choosing to register reductions from specific activities
should follow the additional guidelines contained in Chapter 2,
Reporting Reductions. The inventory methods described in this Chapter
can be applied at various levels including project, activity, and
entity. Some of the issues associated with activity reporting include:

-   **Setting Boundaries.** Entity boundaries are frequently more
    transparent than the boundaries of an activity within an entity. In
    some cases, the activity will be self-contained and relatively easy
    to define. Examples include specific plants or product lines, and
    specific commodity crops or livestock operations within a farm. In
    any case, all reporting entities must clearly define the boundaries
    of their entity and their subentities in a manner that is
    consistently applied in each year\'s report

-   **Certification that emissions will not increase elsewhere within
    the entity's operation.** In order to register reductions from
    activity reports, a small entity must certify that emissions
    elsewhere in the entity's operations do not increase as a result of
    the activities being reported. While this may not require a full
    entity-wide inventory, some analysis will be required for the entity
    to make this certification.

#### 1.A.5 Covered Gases and Global Warming Potentials

The General Guidelines prescribe that reporters must report their
emissions of carbon dioxide, methane, nitrous oxide, perfluorocarbons
(PFCs), hydrofluorocarbons (HFCs), and sulfur hexafluoride (SF6). They
may separately report, but not register, their emissions of
Chlorofluorocarbons (CFCs) \[10 CFR § 300.6 (i)\]. The guidelines
further prescribe:

> Emissions and sequestration should be reported in terms of the mass
> (not volume) of each gas, using metric units (e.g., metric tons of
> methane). Entity-wide and subentity summations of emissions and
> reductions from multiple sources must be converted into carbon dioxide
> equivalent units using the global warming potentials for each gas in
> the International Panel on Climate Change's Third Assessment (or most
> recent) Report, as specified in the Technical Guidelines. \[10 CFR §
> 300.6 (j)\]

PFCs, HFCs and CFCs are not gases, but groups of gases. For reporting
purposes, reporters shall report emissions of HFCs and PFCs from the
list shown on Table 3, page 47 and CFCs from the list shown on page 388
of the Intergovernmental Panel on Climate Change's *Climate Change 2001:
The Scientific Basis*[^2] or a more recent Assessment Report, if
published and approved by the Energy Information Administration.

For reporting or registering reductions, the reporter (and the
Department) will sum emissions across greenhouse gases using the
100-year global warming potentials shown in Table 1.A.2 below. Only
reductions of carbon dioxide, methane, nitrous oxide, perfluorocarbons
(PFCs), hydrofluorocarbons (HFCs), and sulfur hexafluoride (SF6)
emissions may be registered, however.

DOE may add or subtract gases from this list, pursuant to the provisions
of the General Guidelines and any subsequent revisions thereto.

###### Table 1.A.2. 100-Year Global Warming Potentials for Greenhouse Gases

  ------------------------------------------------------------------------------------
  **Gas**                         **Chemical Formula**   **100-Year Global Warming
                                                         Potential**
  ------------------------------- ---------------------- -----------------------------
  Carbon Dioxide                  CO~2~                  1

  Methane                         CH~4~                  23

  Nitrous Oxide                   N~2~O                  296

                                                         

  **Hydroflourocarbons**                                 

  HFC-23                          CHF~3~                 12,000

  HFC-32                          CH~2~F~2~              550

  HFC-41                          CH~3~F                 97

  HFC-125                         CHF~2~CF~3~            3,400

  HFC-134                         CHF~2~CHF~2~           1,100

  HFC-134a                        CH~2~FCF~3~            1,300

  HFC-143                         CHF~2~CH~2~F           330

  HFC-143a                        CF~3~CH~3~             4,300

  HFC-152                         CH~2~FCH~2~F           43

  HFC-152a                        CH~3~CHF~2~            120

  HFC-161                         CH~3~CH~2~F            12

  HFC-227ea                       CF~3~CHFCF~3~          3,500

  HFC-236cb                       CH~2~FCF~2~CF~3~       1,300

  HFC-236ea                       CHF~2~CHFCF~3~         1,200

  HFC-236fa                       CF~3~CH~2~CF~3~        9,400

  HFC-245ca                       CH~2~FCF~2~CHF~2~      640

  HFC-245fa                       CHF~2~CH~2~CF~3~       950

  HFC-365mfc                      CF~3~CH~2~CF~2~CH~3~   890

  HFC-43-10mee                    CF~3~CHFCHFCF~2~       1,500

                                                         

  Sulfur Hexaflouride             SF~6~                  22,200

                                                         

  **Perfluorocarbons**                                   

  Perflouromethane                CF~4~                  5,700

  Perflouroethane                 C~2~F~6~               11,900

  Perfluoropropane                C~3~F~8~               8,600

  Perfluorobutane (FC 3-1-10)     C~4~F~10~              8,600

  Perfluorocyclobutane            c-C~4~F~8~             10,000

  Perfluoropentane                C~5~F~12~              8,900

  Perfluorohexane (FC 5-1-14)     C~6~F~14~              9,000

                                                         

  **Chlorofluorocarbons**                                

  CFC-11 (trichlorofluoromethane) CCl~3~F                4600

  CFC-12                          CCl~2~F~2~             10600
  (dichlorodifluoromethane)                              

  CFC-13                          CClF~3~                14000
  (monoclorotrifluoromethane)                            

  CFC-113 (Freon 113)             CCl~2~FCCIF~2~         6000

  CFC-114                         CClF~2~CCIF~2~         9800
  (dichlorotetrafluoroethane)                            

  CFC-115                         CF~3~CClF~2~           7200
  (monochloropentafluoroethane)                          
  ------------------------------------------------------------------------------------

Source: Intergovernmental Panel on Climate Change, *Climate Change 2001:
The Scientific Basis* (Cambridge University Press, 2001), p. 47; 388.41,
45-6, 388-9.

The Energy Information Administration will specify in its reporting
forms, instructions and related guidance the Global Warming Potentials
and other emission factors to be used by all reporters. In general,
these factors will be those specified in the Technical Guidelines unless
the EIA specifies the use of more current and accurate factors, which
have been adopted by the IPCC, a public agency, a standards-setting
organization or an industry group, and have been publicly documented and
reviewed.

#### 1.A.6 Revisions to Emissions Inventory Reports

Reporters may revise previously submitted inventory reports if the
revision is necessary to:

-   Correct significant material errors and omissions detected after the
    report was accepted by EIA; or

-   To adopt an estimation method from the list approved by DOE that has
    a higher rating than the method previously used to develop the
    inventory and that necessitates changes in historical emissions to
    maintain consistency of the time series.

Participants may submit such corrected reports at any time, as long as
they are accompanied by a description of the changes made, the
significance of their effects on the emission quantities reported, and
an explanation of why they were needed.

**Technical Guidelines for Voluntary Reporting of Greenhouse Gases
Program**

**Chapter 1, Emission Inventories**

### Part B: Collecting Information

Outline

1.  Overview

2.  Identifying Reporting Boundaries

2.1. Who Can Report

2.2. Organizational Boundaries

3.  Identifying Potential Sources of Emission and Sequestration

3.1. Direct and Indirect Emissions

> 3.2. Fossil Fuel Usage

3.3. Industrial Process Emissions

> 3.4. Mining, Oil and Gas Production Emissions

3.5. Waste Treatment and Handling

3.6. Indirect Emissions from Purchased Electricity, Steam, and Hot or
Chilled Water

3.7. Other Indirect Emissions

3.8. Forests, Woody Biomass, and Wood Products

3.9. Agricultural Sources and Sinks

3.10. Geologic Sequestration

4.  Preparing an Emissions Inventory Report

4.1. Needed Steps

> 4.2. Estimating Emissions

4.3. Using Existing Data Systems

4.4. Identifying Organization Elements

4.5. Preparing a Report

4.6. Developing a Reporting Mechanism

**Technical Guidelines Chapter 1, Part B: Collecting Information**

#### 1.B.1 Overview

An entity's inventory report shall include the entity's direct and
indirect emissions released into the atmosphere minus any sequestration
of greenhouse gases from the atmosphere that occurred over the year
covered by the inventory. Inventories are expressed as metric tons of
carbon dioxide (CO~2~) equivalent emissions in a specified year. An
entity's inventory report shall separately identify the data on all
direct emissions, sequestration and indirect emissions. If a reporter
chooses to report emissions associated with CFCs, it must report all
such emissions separately using the special methods for CFC destruction
in Chapter 2.

This chapter provides a general overview of estimating greenhouse gas
emissions in order to report to the Voluntary Reporting Program.
Reporters preparing inventories must:

-   Identify reporting boundaries for the entity.

-   Identify potential sources of emissions and sequestration of
    greenhouse gases.

-   Identify the estimation methods and information sources necessary to
    estimate emissions.

-   Prepare the emissions inventory.

Each of those activities is discussed in the subsequent sections of this
Part B of Chapter 1, and the Part closes with a brief consideration of
institutional issues related to developing an annual entity-wide
emissions inventory. Participation in the Voluntary Reporting Program is
envisaged as a multi-year, long-term activity, and reporters are
encouraged not to view reporting as a one-time event, but as a
continuing process.

#### 1.B.2 Identifying Reporting Boundaries

##### 1.B.2.1 Who Can Report

The General Guidelines provide that:

[Entity]{.underline} means the whole or part of any business,
institution, organization, government agency or corporation, or
household that:

(1) Is recognized under any U.S. Federal, State or local law that
    applies to it;

(2) Is located and operates, at least in part, in the United States; and

(3) The emissions of such operations are released, at least in part, in
    the United States.[^3]

##### 1.B.2.2 Organizational Boundaries

The General Guidelines provide:(a) Each reporting entity must disclose
in its entity statement the approach used to establish its
organizational boundaries, which should be consistent with the following
guidelines:

\(1\) In general, entities should use financial control as the primary
basis for determining their organizational boundaries, with financial
control meaning the ability to direct the financial and operating
policies of all elements of the entity with a view to gaining economic
or other benefits from its activities over a period of many years. This
approach should ensure that all sources, including those controlled by
subsidiaries, that are wholly or largely owned by the entity are covered
by its reports. Sources that are under long-term lease of the entity
may, depending on the provisions of such leases, also be considered to
be under the entity's financial control. Sources that are temporarily
leased or operated by an entity generally would not be considered to be
under its financial control.

\(2\) Entities may establish organizational boundaries using approaches
other than financial control, such as equity share or operational
control, but must disclose how the use of these other approaches results
in organizational boundaries that differ from those resulting from using
the financial control approach.

\(3\) Emissions from facilities or vehicles that are partially-owned or
leased may be included at the entity\'s discretion, provided that the
entity has taken reasonable steps to assure that doing so does not
result in the double counting of emissions, sequestration or emission
reductions. Emissions reductions or sequestration associated with land,
facilities or other sources not owned or leased by an entity may not be
included in the entity\'s reports under the program unless the entity
has long-term control over the emissions or sequestration of the source
and the owner of the source has agreed that the emissions or
sequestration may be included in the entity\'s report.

\(4\) If the scope of a defined entity extends beyond the United States,
the reporting entity should use the same approach to determining its
organizational boundaries in the U.S. and outside the U.S.

\(b\) Each reporting entity must keep separate reports on emissions or
emission reductions that occur within its defined boundaries and those
that occur outside its defined boundaries. Entities must also keep
separate reports on emissions and emission reductions that occur outside
the United States and those that occur within the United States.

\(c\) An entity that intends to register its entity-wide emissions
reductions must document and maintain its organizational boundary for
accounting and reporting purposes.[^4]

## 

#### 1.B.3 Identifying Potential Sources of Emissions and Sequestration

##### 1.B.3.1 Direct and Indirect Emissions

The General Guidelines provide that reporters are obligated to report on
all greenhouse gas emissions and sequestration from sources and sinks
owned and operated by their reporting entity, termed *direct* emissions,
as well as *indirect* emissions arising from the use of electricity, hot
or chilled water, and steam. The Technical Guidelines identifies common
emissions and sequestration sources for which well-defined estimation
methods exist.

Having identified the activities or organizational units whose emissions
should be excluded or included in reporting, the next step is to
identify potential sources of emissions in those areas. This section
will help the reporter to identify which activities are most likely to
involve emissions of greenhouse gases. The most common activity, and
usually the largest source of emissions, is the combustion of fossil
fuels such as natural gas, propane, gasoline, diesel fuel, jet fuel,
fuel oil, coal, and coke. There are, however, many other emissions
sources.

Emissions may be characterized as "direct" or "indirect." An entity's
direct emissions are those emissions from sources in the possession of
the entity at the time the gases are emitted. An example of a direct
emission is exhaust from an automobile that the reporter owns and
drives. An indirect emission is an emission that occurs from a source
owned by a party other than the reporter, but is affected by the
reporter's action. For example, emissions produced during the generation
of electricity, which is produced by a third party and consumed by the
reporter, are indirect emissions.

More specifically, the General Guidelines provide:

> [Indirect emissions]{.underline} means greenhouse gas emissions from
> stationary or mobile sources outside the organizational boundary that
> occur as a direct consequence of an entity's activity, including but
> not necessarily limited to the emissions associated with the
> generation of electricity, steam and hot/chilled water used by the
> entity.[^5]

Indirect emissions from purchased electricity, steam, hot or and chilled
water, which are to be included in emission inventories and may be the
source of registered reductions, are discussed in Part F of this
chapter.

The General Guidelines also provide that emissions from other indirect
sources may be reported separately utilizing applicable reporting
methods as described in the Technical Guidelines. Other indirect sources
may include downstream emissions (and reductions) claimed by the
manufacturers of energy-efficient products; upstream (fuel cycle)
emissions from the manufacture and transportation of fuels; or energy
"embedded" in energy-intensive products manufactured by others, such as
aluminum, steel, cement, or plastics. The reporting of these other
indirect emissions entails considerable complexity because:

-   Indirect emissions (or reductions) may be reported by more than one
    party.

-   Reporting on indirect emissions, by definition, requires information
    on the activities and emissions of other parties. This information
    may be difficult or impossible to obtain. Estimates of information
    made in the absence of precise information are often necessarily
    uncertain and, to a degree, subjective.

Emissions from these other sources of indirect emissions are not to be
incorporated into total emissions and may not be the source of
registered emission reductions, unless explicitly permitted by the
Guidelines.

##### 1.B.3.2 Fossil Fuel Usage

Whenever a fuel containing carbon is combusted (oxidized), the
combustion products will include carbon dioxide (the most common
greenhouse gas), and may also include trace amounts of methane and
nitrous oxide. Because the carbon content of fossil fuels is generally
constant (plus or minus a few percent), the reporter will generally be
able to calculate and report the resulting greenhouse gas emissions if
the quantity of fossil fuels consumed is known.

In most cases, commercial fossil fuels (natural gas, petroleum products,
coal, coal coke, and petroleum coke) will be purchased and combusted by
the reporter. This activity will generate accounting records (of the
purchase), and may generate facilities management records relating to
the use of the fuel, and/or environmental management records (such as
continuous emissions monitoring data) characterizing emissions of
regulated pollutants caused by combustion of the fuel.

Almost all U.S. households, farms, public agencies, and enterprises can
be reasonably expected to purchase and combust fossil fuels. For most
reporters, carbon dioxide emitted from the combustion of fossil fuels
will be the largest source of direct greenhouse gas emissions.[^6] In
general, if a reporter can identify the quantity and heating value of
fossil fuels and quantity of electricity purchased by the reporting
entity, most of the greenhouse gas emissions of the organization can be
easily calculated.

Fossil fuel use can be divided conceptually into stationary source
combustion, mobile source combustion, and non-fuel use. In principle:

-   Stationary source combustion is the burning of fuels in fixed
    facilities.

-   Mobile source combustion is defined as the use of energy to
    transport people and materials from one physical location to
    another.[^7]

-   Non-fuel use includes use of fossil fuels as feedstocks, raw
    materials, lubricants, or solvents. Often, fossil fuel used for
    non-combustion purposes still causes some fraction of the carbon
    locked in the fuel to be emitted to the atmosphere.

Methods for estimating emissions from stationary source combustion and
non-fuel use are described in Part C of this chapter. Methods for
estimating emissions from mobile sources are described in Part D. An
overview of those categories is provided below.

**1.B.3.2.1 Stationary Source Combustion**

Fuel is burned in stationary facilities for a variety of purposes. Among
the most common functions to be considered are:

-   Coal, natural gas, propane, or heating oil for water heating or
    cooling, and for space heating.

-   Coal, natural gas, diesel, and fuel oil for electric power
    generation.

-   Natural gas, coal, or petroleum for raising industrial process
    steam, process heat, or cogeneration.

-   Diesel fuel, propane, or natural gas to drive engines (such as
    diesels) to provide motive power for equipment such as compressors
    or pumps.

-   Oil or gas pipelines with pumps and compressor stations burning
    natural gas or diesel.

Reporters should also be aware of special situations that are discussed
at length in Part C, "Stationary Source Combustion." These include:

-   Byproduct fuel combustion such as flaring, or burning of catalyst
    coke in petroleum refining and the chemical industries, or the use
    of coke oven gas in the steel industry.

-   Own use of fossil fuels that are not purchased such as natural gas
    or petroleum use in oil production operations, refinery gas in
    petroleum refining, and various intermediate chemicals in chemical
    processing.

-   Combustion of petroleum-based waste fuels such as used motor oil or
    tire-derived fuels.

-   Combustion of biofuels or renewable fuels such as wood or wood waste
    and ethanol.

-   Use of fossil fuels as feedstocks (with special accounting
    requirements), as in coke manufacturing and petrochemical
    processing.

Reporters should scrutinize the activities of their organization to
ascertain if any of those special situations apply to them.

Fossil fuel combustion also causes emissions of small amounts of methane
and nitrous oxide, although those trace emissions are rarely measured.
Reporters may estimate them approximately.

**1.B.3.2.2 Mobile Source Emissions**

Mobile sources encompass not only the most obvious transportation
candidates such as planes, trains, and automobiles. It also includes
plant vehicles such as forklifts, construction equipment such as
bulldozers, farm equipment such as combines and tractors, and public
service vehicles such as buses, fire trucks, and ambulances. If your
organization uses any of these vehicles, it is likely that the vehicles
are combusting fossil fuels (usually gasoline, diesel fuel, and/or jet
fuel).

Some of the most common mobile source emissions and the fuel(s) being
combusted are:

-   Motor vehicles, including cars and trucks, typically burning motor
    gasoline or diesel.

-   Locomotives usually burning diesel fuel.

-   Aircraft usually burning jet fuel and occasionally aviation
    gasoline.

-   Construction or farm equipment, normally burning diesel fuel.

-   On-site materials-handling vehicles such as forklifts, burning
    propane or diesel.

There are also a number of special situations in transportation that may
be applicable to particular reporters, but are unlikely to be of general
importance. They include:

-   Combustion of fuels partially derived from biomass fuels, such as
    gasohol.

-   Combustion of alternative fossil fuels, including methanol and
    natural gas.

-   Use of international bunker fuels for aviation and marine
    transportation.

-   Electricity use in the transportation sector.

Those special situations are discussed at greater length in Part D,
"Mobile Sources."

While carbon dioxide will constitute the preponderance of mobile source
emissions, transportation equipment will also normally emit small
amounts of nitrous oxide and methane. While equipment built after 1976
with catalytic converters will produce moderate amounts of nitrous oxide
emissions, even equipment without catalytic converters will produce
trace amounts.

**1.B.3.2.3 Non-Fuel Use of Fossil Fuels***.*

There are a wide range of non-fuel uses of fossil fuels, some of which
produce significant quantities of greenhouse gas emissions. Uses that
produce small amounts of emissions within the boundary of the reporter
may be excluded from the inventory under the *de minimis* provisions
described in the General Guidelines (§300.2 and §300.6). In most other
cases, emissions within the boundary of the reporter from non-fuel use
of fossil fuels must be included in the inventory. The appropriate
treatment of certain specific non-fuel uses of fossil fuels is described
below:

-   *Use of natural gas or petroleum products as petrochemical
    feedstocks*. Feedstock use of fossil fuels is generally limited to
    the chemical industry. Some uses such as ammonia are
    non-sequestering, that is, carbon is emitted to the atmosphere and
    must be reported. Other uses such as ethylene to polyethylene are
    largely sequestering, that is, the carbon remains conserved in the
    end product and need not be reported.

-   *Use of coal to make coke*. Coke making is largely limited to
    integrated steel mills; there are less than 40 coke plants in the
    United States. Most, though not all, of the carbon in coke making is
    conserved into outputs such as coke, coal tars, and coke oven gas
    used as fuel, which are largely oxidized later in the steel-making
    process. If coke or byproducts are sold, however, the subsequent
    oxidation is no longer a direct emission of the coke-maker but
    should be reported by the entity in control of the coke or
    byproducts when the emission occurs unless excluded as a *de
    minimis* emission.

-   *Use of coke as a reduction agent*. Coke is often used in the
    processing of metals, including steel, lead, and copper, as a
    reduction agent---it is burned under conditions of incomplete
    combustion to make carbon monoxide, and the carbon monoxide is used
    to remove oxygen from the ore, which creates carbon dioxide
    emissions. The carbon dioxide emissions should be reported by the
    entity in control of the coke when the emission occurs unless
    excluded as a de minimis emission.

-   *Carbon black manufacture.* There are several plants in the United
    States that use natural gas or oil to make carbon black. About a
    third of the carbon is conserved in the product, the balance emitted
    to the atmosphere. The manufacturer need only report the carbon
    dioxide emitted during manufacturing of the carbon black unless
    excluded as a de minimis emissions.

-   *Use of coke in anode production*. Aluminum smelters use petroleum
    coke to make sacrificial anodes, which are vaporized as part of the
    aluminum smelting process, resulting in carbon dioxide emissions. As
    with other non-fuel uses of fossil fuels, the carbon dioxide
    emissions should be reported by the entity in control of the coke
    when the emission occurs, unless excluded as a de minimis emission.

-   *Lubricants and greases* *(especially motor oil) used in engines and
    machinery*. Used lubricants are often captured and recycled.
    Lubricants that evaporate or are burned (in two stroke engines, for
    example) generate carbon dioxide emissions, while lubricants that
    are lost to the environment may be presumed to oxidize to carbon
    dioxide in the long run. Emissions from the burning of lubricants
    should be reported unless excluded as de minimis, while emissions
    from evaporation are likely to be very small and may be excluded
    from inventories.

-   *Use of carbon-based solvents.* When hydrocarbon-based solvents
    evaporate, the chemicals generally decompose in the atmosphere into
    carbon dioxide. While solvent usage is common, emissions are usually
    so small that they can be ignored. However, where solvent use is a
    significant part of an entity\'s operations, such as dry cleaning
    plants and certain industrial processes, these emissions must be
    estimated and, if not excludable as de minimis, they must be
    included in the entity\'s emissions inventory.

##### 1.B.3.3 Industrial Process Emissions

There are numerous industrial process emission sources that collectively
emit significant quantities of greenhouse gases, although most are found
in only one or two industries. This necessitates that reporters scan a
long list of sources to identify the few that are applicable to their
particular situation. Among the more important industrial process
emissions are:

-   *Carbon dioxide emissions from cement manufacture.* Cement
    manufacturers combust fuels to provide process heat and also to
    calcine limestone into lime, a process that drives off carbon
    dioxide. Cement manufacturers should calculate and report calcining
    emissions.

-   *Other limestone-related emissions.* Lime manufacturers also calcine
    limestone. Some flue gas desulfurizers ("scrubbers") used to remove
    sulfur dioxide react limestone with sulfur and emit additional
    carbon dioxide.[^8]

-   *Multiple sources from iron and steel producers, including the use
    of coke and mineral reducing agents.*

-   *Carbon dioxide released in the manufacture of lime in the Kraft
    pulping process when calcium carbonate* *(CaCO~3)~* *is burned in
    kilns or calciners.* This carbon dioxide is biomass carbon
    originating in wood. Because this is a biogenic source, reporters
    need not include carbon dioxide released by the calcination of
    CaCO~3~ for the purpose of lime manufacture in the Kraft pulping
    process in their emissions inventories.

-   

-   

-   

-   

-   

-   

-   

-   

-   

-   

-   *HFC-32 from freon production.* Producers of HCFC-22 (Freon-22) have
    historically emitted significant quantities of the greenhouse gas
    HFC-32 as a byproduct.

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-   *HFC-134a from motor vehicle air conditioning.* Air-conditioned
    motor vehicles built after 1993 usually use the refrigerant
    HFC-134a, a potent greenhouse gas. Modern air conditioning systems
    do not leak significantly, so the HFC-134a generally remains in the
    vehicle, and authorized dealers are required to recycle the
    refrigerant during repairs. If and when the air conditioning system
    fails, however, the refrigerant will frequently leak into the
    atmosphere. Vehicles that are scrapped or lost in accidents will
    often lose their refrigerant to the atmosphere. A discussion of
    calculating HFC emissions from motor vehicles is included in Part D,
    "Mobile Sources."

    -   *Nitrous oxide from adipic and nitric acid production.* U.S.
        producers of adipic acid and nitric acid have historically
        emitted significant (but controllable) quantities of nitrous
        oxide as a byproduct.

    -   *Various gases from semiconductor manufacturing.* Semiconductor
        manufacturers use several high-GWP greenhouse gases in
        manufacturing, and produce byproduct emissions of
        perfluorocarbons (PFCs) and sulfur hexafluoride (SF~6~).

    -   *PFCs from aluminum manufacturing.* Aluminum manufacturers
        generate byproduct emissions of PFCs, and some magnesium
        producers may use SF~6~ as a cover gas to prevent oxidation of
        the magnesium.

    -   *Refrigerants.* Residential, commercial, and industrial
        reporters may use HFCs as a refrigerant for space cooling,
        refrigeration, or industrial cooling processes. Quantities of
        HFCs may leak into the atmosphere through equipment failure or
        normal leakage.

    -   *Sulfur hexafluoride emissions from breaker switches.* Electric
        power operators may use sulfur hexafluoride as an insulating
        gas. Quantities may leak into the atmosphere under various
        circumstances.

Reporters undertaking any of these activities may reasonably expect to
have industrial process emissions and should calculate and report them.
Methods of estimating emissions from industrial processes are described
in Part E, "Industrial Processes."

##### 1.B.3.4 Mining, Oil and Gas Production Emissions

There are substantial non-combustion sources of emissions of greenhouse
gases from this sector:

-   *Methane emissions from coal mining*. Coal seams typically have
    methane trapped within them. In some cases shale or non-commercial
    coal that coexists with commercial coal seams may also have trapped
    methane. Coal mining will typically release methane into the
    atmosphere, though some portion may be captured or used, and in some
    cases coal companies will act to drain captured methane in advance
    of mining.

-   *Emissions from oil and gas production and transportation*. Natural
    gas is largely methane, and the process of producing and
    transporting natural gas generates fugitive methane emissions. In
    addition, some natural gas fields contain significant admixtures of
    carbon dioxide, which is sometimes separated and vented to the
    atmosphere. Crude oil may also contain dissolved methane, and crude
    oil production, transportation, and refining may be accompanied by
    fugitive methane emissions. Methane emissions from the
    transportation of petroleum products including gasoline and diesel
    fuels are thought to be insignificant.

Estimation of non-combustion emissions from mining and from oil and gas
production is described in Part E, "Industrial Processes."

##### 1.B.3.5 Waste Treatment and Handling

Materials of biological origin, whether plant or animal, will normally
be subject to bacterial decomposition. If that decomposition takes place
anaerobically, that is, in the absence of oxygen, anaerobic bacteria
will predominate, and will produce methane gas as a waste product.

Anaerobic decomposition is commonplace, but it remains the reporter's
obligation to report the resulting methane emissions if the decomposing
biomass is generated within the reporter's organizational boundary.
Methods for estimating methane and nitrous oxide emissions from the
treatment of livestock waste are covered in Part H, "Agricultural
Emissions and Sequestration." Methods for estimating emissions from
other types of waste treatment are discussed in Part E, "Industrial
Processes." Those sources include:

-   *Landfills.* There are thousands of landfills in the United States,
    mostly containing municipal solid waste. The U.S. Environmental
    Protection Agency (EPA) regulates emissions from larger landfills,
    and many landfills are equipped with methane recovery systems that
    serve multiple purposes, including safety, odor control, and
    limiting emissions of urban air pollutants.

-   *Industrial waste*. Some food processors (particularly beer
    manufacturers) have large quantities of biological waste products,
    some portion subject to anaerobic decomposition, generating methane.

-   *Wastewater treatment*. Wastewater treatment may sometimes involve
    anaerobic decomposition, and hence methane emissions. Wastewater
    that contains human or animal waste may also contain significant
    quantities of nitrogen, some of which may decompose into nitrous
    oxide. Under the right circumstances, wastewater treatment plants
    may thus emit significant quantities of nitrous oxide.

##### 1.B.3.6 Indirect Emissions from Purchased Electricity, Steam, and Hot or Chilled Water

Indirect emissions, as defined above, are emissions produced by another
entity, but resulting from the reporter's activities. The General
Guidelines provide that indirect emissions of electricity, steam, and
heated or chilled water must be reported. See Part F, "Indirect
Emissions."

**1.B.3.6.1 Electricity**

Almost all reporters will purchase and use electricity, but reporting
indirect emissions raises an important question: How does the reporter
learn about the emissions of the party who generated the electricity
that was purchased? For almost all electricity users, the Guidelines
specify that indirect emission estimates be based on the regional
indirect emissions factors specified by DOE. These factors are based on
the average emissions intensity of the electricity generated in that
region, regardless of the specific circumstances of individual
electricity users. The only exception is if an individual electricity
user has a contract to purchase power generated by one or more specific
plants. In such cases, the entity may use the average emissions
associated with the power delivered from these plants.

**1.B.3.6.2 Steam**

Steam purchases are less common than electricity purchases.[^9]
Steam-related emissions fall into two categories:

-   In some cities (e.g., San Francisco), district heating utilities
    sell steam to commercial buildings and light industrial customers in
    a manner similar to natural gas and electric utilities. It may be
    possible to learn or infer emissions from the vendor, or in some
    cases default emissions factors may be necessary.

-   Industrial customers, large buildings, malls, and campuses will
    often purchase steam from a plant dedicated to their specific
    requirement. This arrangement is frequently part of a cogeneration
    project, and customers will often know or be able to find out
    specific information on the fuel use and/or emissions of their
    vendor.

**1.B.3.6.3 Hot and Chilled Water**

Many reporters will purchase hot and/or chilled water for heating and
cooling purposes, respectively. In many cases, reporters will maintain
and operate heating and cooling equipment on their premises. Methods for
estimating these emissions can be found in Part C, "Stationary
Combustion." Other reporters will purchase hot and/or chilled water that
is generated by a plant or specific equipment that is owned and operated
by another entity. As is the case with electricity and steam purchases,
reporters in these circumstances may need to obtain information from
their suppliers in order to estimate the emissions associated with these
purchases. If this information is not available, reporters can use
default factors to make an estimate of the emissions associated with
their purchased hot and/or chilled water.

##### 1.B.3.7 Other Indirect Emissions

Reporting entities may choose to report other forms of indirect
emissions, such as emissions associated with employee commuting,
materials consumed or the end uses of products produced, although such
other indirect emissions are not to be included in the entity\'s total
emissions and may not be the basis for registered emission reductions.
All such reports of other forms of indirect emissions must be distinct
from reports of indirect emissions associated with purchased energy and
must be based on emission measurement or estimation methods identified
in the Technical Guidelines or otherwise approved by DOE.

##### 1.B.3.8 Forests, Woody Biomass, and Wood Products

Forests, wood biomass systems, and wood products can be significant
sources or sinks for carbon such as during harvesting or reforestation.
Wood releases carbon dioxide as part of the oxidation process.
Management activities can reduce carbon emissions and increase the
levels of carbon stored. Estimation methods for Forestry-related carbon
emissions and storage are provided in Part I. Examples of management
practices that influence carbon storage include, but are not limited to,
the following:

-   Afforestation of agricultural land can lead to large increases in
    carbon capture and storage by the treated area.

-   Reforestation (regeneration of harvested forest land) can accelerate
    the natural regeneration process and provide for the establishment
    of fast-growing species.

-   Agroforestry can both sequester carbon and decrease requirements for
    fossil energy and energy-intensive chemicals in the production of
    food and fuel.

-   Short-rotation woody biomass energy plantations can sequester carbon
    and provide fuel that displaces fossil fuels in the energy
    production process.

-   Low-impact harvesting methods can decrease the emissions from soil
    disturbance and biomass decay that often follow timber harvest.

-   Recycling and wood products management studies have indicated that
    the carbon contained in harvested trees follows several different
    paths after harvest. Of the carbon that reaches wood products, some
    remains only for a short time (1 to 5 years), but a significant
    amount remains stored in the wood products for long periods (on the
    order of decades) before returning to the atmosphere. Some of the
    carbon in wood products may be recycled or stored in landfills after
    the initial use is discontinued.

Methods of estimating sequestration and emissions from forests, woody
biomass and wood products are covered in Part I, "Forestry Emissions."

##### 1.B.3.9 Agricultural Sources and Sinks

Agriculture has multiple sources of greenhouse gas emissions and carbon
sequestration. Generally, the sources can be categorized by activities
related to crop production and livestock. Estimation methods for each
category are provided in Part H, "Agricultural Emissions and
Sequestration." The categories are described briefly below.

**1.B.3.9.1 Livestock Greenhouse Gas Sources**

*Enteric fermentation.* Enteric fermentation is a normal digestive
process in animals where microbial populations in the digestive tract
break down food and excrete methane gas as a byproduct. Ruminant
livestock---including cattle, sheep, and goats---have greater rates of
enteric fermentation because of their unique digestive system, which
includes a large rumen or fore-stomach where enteric fermentation takes
place. In all animals, diet is an important determinant of the
production of methane. For a further discussion see Section 4.1.2 of
Part H, "Agricultural Emissions and Sequestration."

*Livestock waste.* Livestock waste can be managed in storage and
treatment systems, or spread daily on fields in lieu of long-term
storage. The magnitude of methane and nitrous oxide emissions from
managed livestock waste depends on the conditions of waste handling and
storage.

Installation of anaerobic digesters in livestock waste management
systems can reduce methane emissions from livestock waste and provide an
alternative renewable energy source. Therefore, this action spans the
livestock waste management and indirect emissions estimation methods.
Specific guidance is provided in Box 3.H.1 of Part H on estimating the
impacts of applying this technology to livestock waste management
systems.

**1.B.3.9.2 Crop Production**

*Rice cultivation.* In the United States, rice is grown exclusively on
shallow, continuously flooded fields. Water-logged soils create
conditions for anaerobic decomposition of organic matter, facilitated by
methane emitting "methanogenic" bacteria. Methane from rice fields
reaches the atmosphere in three ways: bubbling up through the soil,
diffusion losses from the water surface, and diffusion through the
vascular elements of plants.

*Nitrous oxide from agricultural soils.* Soil amendments that add
nitrogen to soils drive the production of nitrous oxide. Amendments can
be added to both crop and rangeland soils. Commercial fertilizer,
livestock manure, sewage sludge, incorporation of crop residues, and
cultivation of nitrogen-fixing crops all add nitrogen to soils. In
addition, cultivating highly organic soils (i.e., histosols) enhances
mineralization of nitrogen-rich organic matter, making more nitrogen
available. Nitrogen can be converted to nitrous oxide and emitted
directly in agricultural fields, or it can be transported through
groundwater and run-off to other systems where it is later converted to
nitrous oxide, thus causing indirect emissions.

*Lime application*. Lime is often added to agricultural soils to reduce
acidic conditions. Lime contains carbonate compounds that release carbon
dioxide through the bicarbonate equilibrium reaction when added to
soils.

*Carbon dioxide emissions and sequestration on mineral soils.* The
amount of carbon dioxide emissions and sinks in soils is related to the
amount of organic carbon stored in soils. The net balance of carbon
dioxide uptake and loss in soils is driven in part by biological
processes, which are affected by soil characteristics and climate. In
addition, land use and management affect the net balance of carbon
dioxide through modifying inputs and rates of decomposition. Changes in
agricultural practices such as clearing, drainage, tillage, crop
selection, grazing, crop residue management, fertilization, and flooding
can modify both organic matter inputs and decomposition, and thereby
result in a net flux of carbon dioxide to or from soils.

C*arbon dioxide emissions from cultivation of organic soils*.
Cultivation of organic soils causes oxidation of soil organic matter and
carbon dioxide emissions. As in mineral soils, both carbon dioxide
emissions and sequestration may occur in organic soils, although as long
as organic soils are cultivated they continue to be a net source of
carbon dioxide emissions.

Methods of estimating emissions and sequestration from crop production
are covered in Part H, "Agricultural Emissions and Sequestration."

**1.B.3.10 Geologic Sequestration**

Sequestration refers to a family of methods for capturing and
permanently isolating carbon dioxide from the atmosphere. Geologic
sequestration normally falls into two categories:

-   Intentional extraction of carbon dioxide from industrial processes
    or combustion exhaust streams, combined with placing the carbon in a
    form or location in which it will not be released into the
    atmosphere. This is likely to involve the injection of carbon
    dioxide into permanent underground storage.

-   Injection of carbon dioxide into underground reservoirs as part of
    an enhanced oil recovery activity.

Most geologic sequestration activities are currently associated with
enhanced oil recovery, which requires reporters to take care that the
sequestration is not temporary and that carbon dioxide injected into the
ground is not offset by its release elsewhere. Geologic sequestration
issues are described in Part G, "Geologic Sequestration."

#### 1.B.4 Preparing an Emissions Inventory Report

##### 1.B.4.1 Needed Steps

Once a reporter has identified his or her organizational boundaries and
the likely sources of emissions, the next step is to prepare an
emissions inventory. To do this the reporter will need to:

-   Identify prospective methods of estimating emissions from the
    relevant sources, and the information that would be potentially
    required to calculate emissions.

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-   Identify information systems in which emissions information or
    activity data relevant to the estimation of emissions is already
    being collected or might feasibly be collected.

-   Identify organizational elements that have custody of the relevant
    information or that might be in a position to collect the
    information.

-   Collect the data, estimate emissions, prepare an inventory, and
    submit a report to the Energy Information Administration's Voluntary
    Reporting of Greenhouse Gases Program.

-   Develop a mechanism by which emissions data can be routinely
    collected and assembled into a verifiable entity-wide emissions
    estimate at an acceptable cost.

##### 1.B.4.2 Estimating Emissions

Emissions of greenhouse gases may be measured in several different ways:

**Direct measurement** - by continuous or periodic measurement of
emissions. To ensure consistency and reliability, reporters using any
direct measurement data should ensure that their measurement systems are
subject to periodic calibration practices. Due to the wide variety of
emission sources and methods for measuring them, this guidance does not
provide specific instruction on calibrating measurement systems for each
emission source discussed herein.

Reporters to the Voluntary Reporting of Greenhouse Gases Program
(1605(b) Program) that directly measure their emissions are expected to
follow internal quality control assessments that verify the accuracy of
their measurement systems. Specific, internationally accepted standard
methods for measuring greenhouse gas emissions exist for some
industries. Where specific methods exist, reporters are encouraged to
follow them; where possible, this guidance refers reporters to readily
available, published authorities that provide specific instruction of
this nature.

In the absence of industry-specific standard methods, reporters should
follow internationally accepted, generalized standard methods for
managing and calibrating measurement systems. One such organization
providing guidance for complying with internationally accepted standards
is the International Organization for Standardization (ISO). Reporters
seeking general guidance on methods for managing and calibrating
measurement systems should consult the ISO's guidance document, *ISO
10012 - Measurement Management Systems - Requirements for Measurement
Processes and Measuring Equipment*.[^10] This document provides generic
guidance designed to help organizations establish and operate an
effective measurement management system that features the following:

-   Clearly specified measurement requirements that can be shown to be
    satisfied.

-   Effective, accountable management that establishes quality
    objectives for the organization's metrological function.

-   Defined and documented management of resources associated with the
    metrological function, including human resources, information
    resources and material resources.

-   Clear guidelines for establishing, maintaining and documenting the
    accuracy, calibration and uncertainty associated with measurement
    equipment and procedures.

-   Specific, controlled conditions under which to perform measurement
    processes.

-   Procedures for ensuring continued conformity with established
    standards while maintaining and realizing opportunities for making
    improvements to the measurement system.

**Inferred measurement -** derived from a measurement or set of
measurements made at a single point in time (typically for sources that
are small and/or difficult to measure). Alternatively, direct or
inferred measurements of an emission source at a particular point in
time may be used to develop an "emissions factor" that links estimated
emissions with a measurable activity that presumptively causes the
emissions to occur. For example, if EPA's Office of Mobile Sources
determines (based on testing sample vehicles) that a 1998 model car
emits an average of 0.02 g of nitrous oxide per mile traveled, this
factor can be applied to vehicle travel data to estimate nitrous oxide
emissions (i.e., multiply total miles traveled by emissions per mile).

**Mass balance** - calculate the quantities of emissions by measuring or
calculating the quantities of a specific source, the individual source's
compounds, reaction products, and outputs. For example, if 2 kilograms
of HFC-134a was initially injected into an automobile air conditioner
and three years later the remaining 1 kilogram is removed and recycled,
one can safely assume that the other kilogram was emitted to the
atmosphere.

No single method is feasible, best, or most accurate for all sources and
situations. In most cases, the estimation method will need to be matched
to the particular source. There are multiple considerations in making
this determination, which include the following:

-   **Availability of Information**. Many electric power generators and
    large industrial sources measure carbon dioxide emissions directly,
    using continuous emission monitors (CEMs), as required by Title IV
    of the Clean Air Act Amendments. Most entities track commercial fuel
    purchases.

-   **Cost and feasibility**. Some methods may be extremely expensive,
    others infeasible. Reporters should choose methods that are
    sustainable over time.

-   **Accuracy**. Some methods are more accurate than others, although
    accuracy is specific to a linkage of method and source.

-   **Size of the source**. Simple, less accurate methods may be
    acceptable for small, uncontrollable sources.

-   **Controllability and feasibility of reduction action**. If a
    reporter expects to show, now or in the future, that emissions from
    a particular source have been reduced, the credibility of his report
    will be enhanced by taking extra care with measuring current
    emissions from that source.

-   **Variability and performance over time**. Emissions estimation
    methods should accurately reflect changes in emissions over time.

-   **Ancillary benefits**. Reporters should consider opportunities for
    synergies in collecting greenhouse gas-related data along with other
    information. For example, systems that monitor emissions of
    regulated pollutants may be modified to monitor emissions of
    greenhouse gases; data systems for operational management and
    control may be modified to include activity data for emissions
    estimation.

Reporters should choose estimation methods that are most suitable for
their particular circumstances. Collecting new data in the field may be
necessary in some cases, but one should not automatically assume that
such efforts will be necessary. A better first step is to consider what
information systems are already in place, and try to ascertain what
information is already being collected.

##### 1.B.4.3 Using Existing Data Systems 

Large organizations typically have multiple information systems that
collect information relevant to estimating greenhouse gas emissions.
These might include:

*Operational Data Systems*. Operational data may be defined as reporting
on physical quantities of materials consumed or products manufactured.
In contrast to financial data, which are always reported to
headquarters, operational data are collected only if they are deemed
useful for management information and control or necessary for
regulatory purposes. If collected, operational data are often held at
the facility or division level, and not reported to the reporter's
headquarters. Much of the information deemed "of interest" to someone
preparing a greenhouse gas emissions inventory falls into the category
of operational data.

For example, fuel or energy consumption data are rarely independently
reported to headquarters unless fuel costs are considered to be a
"major" controllable cost element. Many energy-intensive industries have
centralized energy management programs, but for other types of
organizations this information is the province of facility or process
managers. For public agencies or service industries, fuel use is often
just another bill paid by the accountants.

Expensive transportation equipment such as aircraft, locomotives,
vehicle fleets, and construction equipment will usually be carefully
maintained and the maintenance supported by detailed records. An
airline, for instance, must know the provenance of every spare part
applicable to an aircraft, and know when every aircraft subsystem is due
for scheduled maintenance. Maintenance records will often specify how
many hours an aircraft has been flown, or how many miles a truck has
been driven. Such information may be helpful in estimating greenhouse
gas emissions. In common with other operational data, however,
maintenance and facilities management data are rarely forwarded up the
organizational chain of command.

Most aluminum producers probably view output of aluminum as a key index,
and plant managers report output data to headquarters. Exotic inputs
such as SF~6~ or HFC-134a are much less likely to be of interest to
headquarters. If the relevant operational data are not reported to
headquarters, inventory managers might visit with plant or facility
managers to learn what types of information are available locally, and
persuade them to begin forwarding such data. It is also possible that
the information is already being reported, just through an unexpected
reporting channel.

Inventory managers should be alert to the many not-so-obvious forms of
reporting, and that "piggybacking" on existing reporting systems is
generally the lowest cost way to get started in greenhouse gas emissions
reporting. Some other systems that may exist include:

*Facilities Management and Maintenance Systems*. Many organizations use
"facility management" to describe the function of supervising the
operation and maintenance of building or equipment complexes. Facility
managers are often responsible for energy consumption, and frequently
keep detailed records of fuel use, equipment utilization, and
maintenance. Those records will often prove useful in preparing an
emissions report, provided one has access to the data.

*Financial Accounting Systems*. Nearly every institution has some type
of financial accounting system, within which there are relevant
subsystems that include the following:

-   **Accounts payable.** These systems generally track how much money
    has been paid, the vendors to whom funds are paid, dates of
    payments, cost centers to which expenses are charged, and invoices
    against which payments have been rendered. In many cases the
    quantity of fuel or electricity purchased will be available either
    directly from the accounting system or indirectly from scrutiny of
    invoices. Accounts payable data may also indicate purchases of
    high-GWP gases such as sulfur hexafluoride, HFCs, or PFCs, if such
    gases are in use.

-   **Inventory.** These systems may track stocks and changes in stocks
    of fuels and possibly high-value commodities. If firms have storage
    capacity and large stocks of petroleum or solid fuels, changes in
    inventory will be a more accurate indicator of actual consumption
    than fuel purchases. Firms may maintain inventories (and records) of
    high-GWP gases as well.

-   **Contract records.** Energy services will frequently be purchased
    pursuant to contracts that may also contain useful information
    (e.g., prices and vendor names), which can be used to interpret
    accounts payable records. Aspects of fuel quality also may be
    specified in contracts.

Organizations differ greatly in how the accounting function is
organized - from highly centralized at headquarters to decentralized in
subsidiary units where only periodic summary financials are forwarded to
the main unit. The information that is useful for inventory preparation
is most likely to be found close to where actual bills are being paid.
Consequently, it may be necessary for the persons responsible for
greenhouse gas reporting to identify the appropriate personnel to
contact, ascertain what information they possess, and develop
cooperative relationships to facilitate the greenhouse gas reporting
effort.

*Environmental Reporting Systems.* Many organizations report emissions
and environmental data to the EPA and other environmental agencies.
Although greenhouse gas emissions are not currently subject to Federal
regulation, there is at least one Federal requirement to report such
emissions \[42 U.S.C. 7651k note\]. In addition, information systems
currently used for other environmental reporting may also collect
information about greenhouse gas emissions, or may be modified to
collect greenhouse gas emissions data. For example:

-   **Environmental Reporting**: **Clean Air Act.** There are about
    2,000 facilities in the United States that are required to report
    sulfur dioxide and nitrogen oxide emissions to the EPA under
    provisions of the Clean Air Act Amendments of 1990, using continuous
    emission monitors. Those facilities are also required to report
    carbon dioxide emissions for calibration and verification purposes.
    Numerous other facilities are permitted to report emissions using
    other methods, including mass balance. Many gas-fired facilities
    report carbon dioxide emissions to EPA using strictly specified
    fuel-sampling procedures, and checked using tracking systems. This
    information is in the public domain.

-   **Environmental Reporting: Criteria Pollutant Reporting**. Many
    facilities are required to report their emissions of criteria
    pollutants to State regulatory agencies, or alternatively to report
    expected future emissions for permitting purposes. This information,
    some of which may be in the public domain, can be useful to identify
    possible emissions of greenhouse gases. Nitrogen oxide and carbon
    monoxide emissions are generally indicative of combustion, probably
    of fossil fuels, and may help indicate where carbon dioxide is being
    emitted. Emissions of non-methane volatile organic compounds may be
    indicative of possible methane emissions. Data on emissions of
    certain greenhouse gases, particularly methane and carbon dioxide,
    are in some cases collected but not reported.

Environmental reporting is usually the province of environmental
management or environmental safety and health groups. As in the case of
financial reporting, environmental management may be centralized or
decentralized. Organizations that operate in multiple countries or are
subject to multiple regulatory jurisdictions tend to be organized around
those jurisdictions.

*Safety reporting* is relevant to greenhouse gas reporting in several
specialized contexts. Coal mine, petroleum, and landfill operators have
an acute interest in avoiding methane hazards. Safety personnel track
emissions, leak repairs, or equipment usage to identify hazards or
compute safety metrics. More generally, safety personnel may collect
operating data for the computation of safety metrics.

*Economic, Regulatory, and Trade Association Reporting*. Many large
firms and facilities are required to report fuel consumption and
industrial production to various government agencies, including the
Department of Commerce, the DOE's Energy Information Administration
(EIA), and the Federal Energy Regulatory Commission (FERC). Individual
firm or facility reports are rarely in the public domain, although
inventory managers can obtain copies of their own company reports from
the person submitting the report. Among the reporting systems that might
be useful in specific instances are the following:

-   Large electric power plants report fuel consumption and stocks to
    the EIA.

-   Large regulated electric utilities, including public sector
    utilities, report to the FERC on FERC Form 1, which covers electric
    energy purchased and sold and also considerable amounts of
    enterprise-level data.

-   Cement plants are surveyed on fuel consumption every two years by
    the Minerals Information Service of the U.S. Geological Survey
    (USGS), and report production to the USGS annually. The USGS also
    collects data on a range of limestone uses, which may be helpful in
    calculating emissions from the use of lime or limestone as a
    reducing agent.

-   Oil refineries report fuel consumption to the EIA every other year.

-   Coke plants report fuel consumption and output to the EIA every
    year.

-   Natural gas producers and natural gas plants report to the EIA on
    gas balances, which include production, fuel consumption, and
    non-hydrocarbon gases removed every year.

-   Many manufacturing establishments report physical production to the
    U.S. Census Bureau as part of the *Current Industrial Reports*. Many
    manufacturers also report additional data, including energy
    consumption data, to the Census Bureau as part of the *Annual Survey
    of Manufacturers*. A sample of establishments, including most large
    energy consumers, is asked every four years to report detailed
    information on energy consumption as part of the *Manufacturing
    Energy Consumption Survey* (MECS).

-   Construction, mining, and oil and gas production establishments also
    report a range of data, including some energy data, to the U.S.
    Census Bureau.

-   Several trade associations, notably the Integrated Solid Waste
    Management Association, the American Chemical Council, and the
    American Iron and Steel Institute, have organized energy data
    reporting programs among their members. Reporting of output data to
    trade associations is also common.

In most cases, individual establishment or facility data from these
statistical programs are not in the public domain. Reporters may be
able, however, to identify the internal corporate data systems (usually
corporate compliance personnel) that support the reports filed for those
programs, and adapt either the information or the system that collects
the information for greenhouse gas reporting purposes.

*Tax Reporting*. Operating data may also emerge from tax reporting.
Firms that produce, purchase, or sell products subject to royalties or
excise taxes (e.g., transportation fuels), may have or be able to obtain
operating data from those records. Other activities such as renewable
energy production and landfill methane operations are eligible for
Federal or State income tax credits, which require collecting and
specifying operating data for the tax authorities.

##### 1.B.4.4 Identifying Organizational Elements

Having defined the scope of reporting, considered possible sources of
emissions and sequestration, and determined what information is already
collected by the organization, the next step is to define which
organizational elements need to be involved in developing the inventory.
While it is common to think of inventory development as being primarily
a technical problem, experienced practitioners in large organizations
tend to think of the technical problems as being one of the simplest
aspects of inventory preparation. A more acute problem often is securing
the consent and cooperation of the people and organizational units who
actually possess the information needed to prepare an inventory. This
task frequently requires tact, diplomacy, and senior management
commitment.

##### 1.B.4.5 Preparing a Report

The most difficult aspect of preparing an emissions report is usually
collecting the necessary information. Actually preparing an emissions
inventory and reporting emissions to the Energy Information
Administration is largely an exercise in arithmetic, form filling, and
the avoidance of egregious error. Reporters should pay attention,
however, to the categorization of the information required by the
Voluntary Reporting Program.

##### 1.B.4.6 Developing a Reporting Mechanism

It may turn out that not all the needed information is already
available. In some cases, new data collection systems may need to be
funded and put in place. New data systems should, in general, be placed
where there are people with access to the facilities and information
needed to collect the data. The first step, however, is always to
determine what can be accomplished with existing data and existing
systems.

In either case, it is important to keep in mind that greenhouse gas
emissions reporting under the program is not a "one off" exercise. The
reporter should expect to be preparing emissions reports every year. *Ad
hoc* arrangements and volunteer labor will tend to come unraveled if
repeated too many times.

Hence, in organizing reporting, reporters should keep in mind methods
for automating and institutionalizing the necessary information flows,
and giving participants a stake in the success of the system. In this
respect, organizing a greenhouse gas reporting system in a large
organization reflects many of the institutional challenges endemic in
motivating and coordinating action across a large organization. The
longer-run requirements for a sustainable reporting system include:

-   A person or group with responsibility, authority and resources to
    prepare an organizational emissions inventory to an adequate
    standard.

-   Management "buy in."

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-   Matching actual and potential emissions sources to particular
    organizational units, and to responsible individuals or groups
    within those organizational units.

-   Identifying an estimation method for each emissions source, and data
    source(s) consistent with the chosen estimation method.

-   Funding and organizational approvals so that the responsible party
    is empowered to collect or obtain the necessary data for each source
    and to estimate emissions or forward the data.

-   Developing an information system (not necessarily computer-based)
    that permits the necessary information to flow to the persons
    responsible for preparing the inventory.

Quality assurance and verification to ensure that the correct sources
are being measured using appropriate methods, to understand the quality
of the underlying data being used, and to ensure that calculations are
performed correctly and reported accurately.

**Technical Guidelines for Voluntary Reporting of Greenhouse Gases
Program**

**Chapter 1, Emission Inventories**

### Part C: Stationary Source Combustion

Outline

### 

1.  Overview

> 2\. Estimation Methods
>
> 2.1. Overview
>
> 2.2. Direct Measurement
>
> 2.3. Mass Balance
>
> 2.4. Inference
>
> 3\. Common Sources: Carbon Dioxide
>
> 3.1. Coal
>
> 3.2. Natural Gas
>
> 3.3. Middle Distillates and Heavy Fuel Oil
>
> 3.4. Liquefied Petroleum Gas (LPG)

4.  Common Sources: Methane and Nitrous Oxide

> 5\. Combustion from Special Situations
>
> 5.1. Refinery Gas
>
> 5.2. Petroleum Coke
>
> 5.3. Flaring of Natural Gas or Crude Oil
>
> 5.4. Petroleum-Based Waste and Byproduct Fuels
>
> 5.5. Biogenic Fuels (Bagasse, Wood, Wood Waste, and Ethanol)
>
> 5.6. Municipal Solid Waste and Landfill Gas
>
> 6\. Special Situations: Nonfuel Use of Fossil Fuels

**Technical Guidelines Chapter 1, Part C:\
Stationary Source Combustion**

#### 1.C.1 Overview

This section covers estimating emissions of greenhouse gases from
stationary source combustion and also from non-fuel use of fossil fuels.
In general, reporters can reasonably expect that over 95 percent of
their GWP-weighted emissions from stationary source combustion will take
the form of carbon dioxide (CO~2~), with minor quantities of methane
(CH~4~) and nitrous oxide (N~2~O) emissions.

Most stationary source combustion emissions will be caused by the
combustion of commercial fossil fuels: coal, petroleum, and natural gas.
Carbon dioxide emissions from the combustion of commercial fossil fuels
may be accurately measured by the use of continuous emission monitors,
if available, or by mass balance, properly applied. Emissions of methane
and nitrous oxide from combustion are difficult to measure accurately,
but fortunately are rather small.

There is also a range of special situations that are unlikely to be of
importance to reporters generally, but may be significant for particular
reporters. Those special situations include the combustion of
non-standard fuels such as refinery gas, petroleum coke, or waste fuels
such as lubricating oil or tire-derived fuel; combustion of biomass; and
non-fuel use of fossil fuels. These special situations are discussed at
the end of this section.

#### 1.C.2 Estimation Methods

##### 1.C.2.1 Overview

Stationary source combustion is defined as the burning of a fuel to
produce heat or motive power using equipment in a fixed location.
Stationary source combustion includes electric power generation,
residential and commercial space heating or district heating, industrial
process heating, cogeneration (also called "combined heat and power"),
and powering engines for diverse purposes, including driving compressors
and pumps.

Stationary source combustion almost always generates emissions of
greenhouse gases because the fuel contains carbon, which is oxidized to
form carbon dioxide. Almost all (98 to 99 percent) of the carbon in the
fuel is typically oxidized to carbon dioxide and goes up the stack as an
emission. In contrast with many other types of emissions, carbon dioxide
emissions can often be accurately estimated using mass balance
calculations (see the explanation in the box, "How Mass Balance Works").
In addition, many large stationary source combustion sources in the
United States (and effectively all large coal-fired units) are equipped
with continuous emissions monitors (CEMs) that record carbon dioxide
emissions and report their amounts to the U.S. Environmental Protection
Agency (EPA).

Stationary source combustion also produces trace quantities of methane
and nitrous oxide. Trace emissions of methane are derived from unburned
or partially burned fuel and are most common when combustion
temperatures are low and/or oxygen is deficient. High levels of
combustion-related methane emissions are most probable when the fuel is
heated but not combusted, causing complex hydrocarbons to break down
into simpler components, including methane.

It is not entirely clear how and why nitrous oxide is emitted from
combustion, but it appears to be a reaction product of nitrogen oxides
(NO~x~). The EPA reports that nitrous oxide emissions are more prevalent
at lower combustion temperatures. Reporters, however, should devote the
bulk of their effort to calculating carbon dioxide emissions because 95
to 99 percent of global warming potential-weighted emissions from
stationary source combustion are usually attributable to carbon dioxide.

There are three general methods for estimating emissions from stationary
source combustion: direct measurement, mass balance, and inferring
emissions from activity data and sample emissions measurement. For
estimating carbon dioxide, mass balance and direct measurement (such as
stack monitoring) can both produce accurate results. Inferred emissions
can generally be expected to be less accurate, but are acceptable for
estimating minor amounts of emissions from methane and nitrous oxide.

##### 1.C.2.2 Direct Measurement

*Continuous Emissions Monitoring* *(CEM) for Regulatory Purposes*.
Emissions monitoring requires inserting a probe into the exhaust stack
of a combustion system and continuously measuring and recording
concentrations of carbon dioxide and other gases. Actual emissions are
estimated by calculating the density and flow rate of exhaust gases
through the stack. Under the Clean Air Amendments of 1990 (CAAA), about
2,000 power plants and industrial boilers are required to install CEM
equipment in their stacks and report emissions of carbon dioxide to the
EPA.[^11]

*Other Emissions Monitoring*. Reporters may monitor their stack
emissions even when not required to by the CAAA. They may be complying
with other environmental regulations or collecting boiler performance
information. Reporters should use unregulated emissions monitoring data
with caution, particularly for carbon dioxide. Moving from a
concentration sample to an accurate estimate of mass emissions over time
requires solving some challenging measurement and calibration problems
that have already been solved for regulatory monitoring. Reporters who
use monitoring data should ensure that the methods used and the quality
of the data collected is comparable to data that would be acceptable to
the EPA for reporting under Climate Leaders.

##### 1.C.2.3 Mass Balance

Carbon dioxide emissions can usually be computed to an accuracy of five
percent or better by using the following general formula:

CE = QF \* CC \* FC

> Where

CE = carbon dioxide emissions (metric tons)

QF = quantity of fuel (measured in weight, volume, or heating value)

> CC = carbon coefficient (a ratio, metric tons carbon dioxide per
> "unit" of fuel, as above)

FC = fraction combusted

Fuel quantity may be expressed in terms of weight (tons or pounds of
fuel); volume (barrels, gallons, cubic feet, or cubic meters of fuel);
or heating value (million Btu or joules, either higher heating value or
lower heating value). The carbon coefficient for the fuel is the
theoretical maximum carbon dioxide emission rate expressed in terms of
units of carbon dioxide per unit of fuel denominated by any of these
measures. Often, as is the case in these guidelines, a default emission
factor may be calculated by multiplying the carbon coefficient (CC) by
the assumed fraction combusted (FC).

Given the diversity of possible measures, which measure should reporters
actually use? In general, reporters should use the measure of fuel
quantity that most accurately represents the characteristics of the fuel
actually consumed by the reporter. Reporters should minimize the use of
default values by substituting parameters based on actual measurements
whenever possible.

###### Table 1.C.1. Getting the Most Accurate Results from Mass Balance {#table-1.c.1.-getting-the-most-accurate-results-from-mass-balance .Heading6}

+------------------+----+--------------------------------------+------+
| **If the         | ** | **Then calculate:**                  | ###  |
| reporter         | Fu |                                      | #### |
| knows.....**     | el |                                      | # Ra |
|                  | ** |                                      | ting |
+------------------+----+--------------------------------------+------+
| Weight & carbon  | Co | Weight x carbon content              | A/B  |
| content          | al |                                      |      |
+------------------+----+--------------------------------------+------+
| Actual heating   | Co | Heating value x emission factor      | A/B  |
| value            | al |                                      |      |
+------------------+----+--------------------------------------+------+
| Weight only      | Co | Weight x default heating value x     | C    |
|                  | al | emission factor                      |      |
+------------------+----+--------------------------------------+------+
| Weight & carbon  | O  | Weight x carbon content              | A/B  |
| content          | il |                                      |      |
+------------------+----+--------------------------------------+------+
| Actual heating   | O  | Heating value x emission factor      | A/B  |
| value            | il |                                      |      |
+------------------+----+--------------------------------------+------+
| Weight only      | O  | Weight x assumed carbon content x    | C    |
|                  | il | emission factor                      |      |
+------------------+----+--------------------------------------+------+
| Volume & actual  | O  | Volume x density x assumed carbon    | A/B  |
| density          | il | content                              |      |
+------------------+----+--------------------------------------+------+
| Volume only      | O  | Default heating value x emission     | C    |
|                  | il | factor                               |      |
+------------------+----+--------------------------------------+------+
| Heating Value    | G  | Heating value x emission factor      | A    |
|                  | as |                                      |      |
+------------------+----+--------------------------------------+------+
| Volume only      | G  | Volume x default heating value x     | B    |
|                  | as | emission factor                      |      |
+------------------+----+--------------------------------------+------+

When the actual carbon content of the fuel is known (based on an
ultimate analysis), the most accurate calculation of mass balance
emissions is generally based on weight, although because the carbon
content of a fuel (particularly coal) can vary considerably from one
sample to another, a fairly intensive sampling program is required to
produce the most accurate results. More commonly, the reporter will not
know the carbon fraction of the fuel (or will not know it with
sufficient precision), but will know the heating value (this would be
typical of natural gas, coal, and some fuel oils). In this case, the
most accurate mass balance calculation would be based on heating value
and a default emission factor.

Liquid fuels, however, are often sold by volume alone, rather than by
weight or heating value. If the reporter knows neither the heating value
nor the carbon fraction of the fuel, the most accurate approach is to
use actual density (since volume times density = weight.). It will also
frequently be the case for some liquid fuels, such as diesel and
gasoline, that *only* the volume of fuel is known. In those instances
the reporter must multiply fuel volume by an assumed density and carbon
content per ton, or alternatively, multiply fuel volume by an assumed
heating value per unit volume and an emission factor expressed per unit
heating value. Both approaches provide reasonably accurate results,
though not as accurate as when actual heating value or density is known.

##### 1.C.2.4 Inference

Mass balance estimates are irrelevant to emissions of methane and
nitrous oxide (as well as criteria pollutants). Emissions estimates must
necessarily either be made directly, from observed emissions, or
indirectly by inference from prior direct observation, either of the
unit in question, or of some other comparable unit.

The EPA and the Intergovernmental Panel on Climate Change (IPCC) have
published a set of coefficients for methane and nitrous oxide emissions
from various classes of stationary source combustion devices. Those
emission coefficients are based on a relatively small set of sample
tests that are used to infer an "average" or "typical" emission factor,
expressed as emissions per unit of fuel input or power output. The
default emission factors are not necessarily the most accurate measures
of actual methane and nitrous oxide emissions because these emissions
are not closely linked to fuel input or power output. They are probably
more closely linked to fuel-air ratios and completeness of combustion
generally (for methane) and fuel-air ratios and peak combustion
temperatures (for nitrous oxide). Available research shows that actual
emissions of methane and nitrous oxide from stationary source combustion
of fossil fuels are likely to be extremely small, even if the exact
number is unknown.

#### 1.C.3 Common Sources: Carbon Dioxide

##### 1.C.3.1 Coal

Coal is used in the United States primarily for the generation of
electric power and is typically combusted in large (greater than 100 MW)
steam turbine electrical generating plants. Virtually all such units
have continuous emissions monitors providing carbon dioxide emissions
data to the EPA under Title IV of the CAAA.[^12] These plants are
typically "pulverized coal" units, in which coal is ground to a powder
and sprayed into the combustion chamber, ensuring nearly complete
combustion.

There are also significantly smaller and older "spreader stoker" units
in which lump coal is mechanically introduced into the combustion
chamber, and there perhaps remain a few units in which a person
("stoker") physically shovels coal into a furnace. These units are less
likely to have continuous emissions monitors installed, and are more
likely to be smaller scale units that provide space heating for building
or campuses.

Coal-fired residential furnaces and stoves were once commonplace in the
United States, but have been largely replaced in recent decades. The
units that remain typically burn small quantities of high-grade
anthracite coal, prized for its smokeless properties.

Carbon dioxide emissions data provided to the EPA under the CAAA are
rated "A." (For a description of the emissions rating system and its
uses, please see Part A of this Chapter.)

Carbon dioxide emissions estimates using mass balance may also be used,
although the rating of such estimates will depend on the quality of the
information used to estimate the emissions. Emissions estimates from
large coal-fired units using mass balance may also be rated "A,"
provided the mass balance estimate has all of the following features:

-   Fuel consumption is calculated by measuring fuel fed to the boiler
    rather than by fuel purchases or deliveries (this ensures that stock
    change is not counted as combustion).

-   A plant-specific emission factor is calculated based on a periodic
    (at least monthly) analysis of coal samples as fed to the boiler,
    including analysis of both heating value and carbon content.

-   The calculation takes into account carbon not oxidized into the
    atmosphere.

-   The calculation takes into account non-combustion related carbon
    dioxide emissions arising from sorbent reactions in flue gas
    desulfurization units (if applicable).

Some large coal-fired units may not have EPA-regulated continuous
emissions monitors. (For example, the units might be located outside the
United States). Reporters may use data from non-EPA rated continuous
emissions monitors if the data are reported to another Governmental
authority for regulatory purposes. Those submissions would also be rated
"A."

Table 1.C.2 illustrates ratings achievable for coal-fired units using
mass balance calculations.

###### Table 1.C.2. Quality Ratings for Estimation of Emissions for Coal-Fired Plants {#table-1.c.2.-quality-ratings-for-estimation-of-emissions-for-coal-fired-plants .Heading6}

  ---------------------------- ------------------- ------------------- --------------
  **Plant Type**               **Emission Factor**                     

                               **Plant-specific,   **Plant-specific,   **Default
                               periodic analyses** single analysis**   based on coal
                                                                       rank**

  CEM or mass balance          A                   NA                  NA
  supervised by a regulatory                                           
  agency                                                               

  Mass balance, measured       A                   B                   C
  consumption                                                          

  Estimated consumption based  B                   C                   D
  on purchases or deliveries                                           
  ---------------------------- ------------------- ------------------- --------------

Table 1.C.3 provides default emission factors for U.S. coals assuming 99
percent combustion.

###### Table 1.C.3. Emission Factors for U.S. Coal Consumption Assuming 99 Percent Combustion {#table-1.c.3.-emission-factors-for-u.s.-coal-consumption-assuming-99-percent-combustion .Heading6}

  ------------------------------------------------------------------------
  **Consuming Sector/Coal Rank**         **Emission Factor 
                                         kgCO~2~/10^6^ Btu 
                                         (HHV)**           
  -------------------------------------- ----------------- ---------------
                                         **CO~2~**         **Carbon**

  **Consuming Sector**                                     

  Electric Power                         94.31             25.72

  Industrial Coking                      93.04             25.37

  Other Industrial                       93.44             25.48

  Residential/Commercial                 94.53             25.78

  **Coal Rank**                                            

  Anthracite                             102.58            27.98

  Bituminous                             92.53             25.24

  Sub-bituminous                         96.12             26.22

  Lignite                                95.47             26.04
  ------------------------------------------------------------------------

Source: Energy Information Administration, Documentation for Emissions
of Greenhouse Gases in the United States 2003, May 2005, Table 6-2, p.
190, web site:
www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

The factors shown in Table 1.C.3 were developed using a sample of U.S.
coals. Coals burned abroad, and particularly coals produced and consumed
within developing countries, may have somewhat different
characteristics. Those coals may contain additional non-hydrocarbon
materials and hence have a lower heating value (and lower carbon
emissions) per ton of coal burned than in the United States, and
reported heating values may exceed actual heating values. Similarly,
"waste coal" burned in the United States may have idiosyncratic
characteristics, and reporters using waste coal or reporting emissions
from abroad should make specific efforts to obtain emission factors
derived from analysis of the actual coal being burned rather than using
default emission factors.

The emission factors provided in Table 1.C.3 further assume that the
fraction combusted of coal consumed in the U.S. is 99 percent. If the
reporter is not using a default emission factor but instead has specific
information on the carbon content of the coal combusted, the 99 percent
default fraction combusted may be assumed. If the reporter also has
specific information on the amount of carbon left uncombusted (for
example, by measuring carbon content in ash) this specific information
should be used.

##### 1.C.3.2 Natural Gas

Pipeline-quality natural gas is usually a homogenous product, typically
sold by volume with a price adjustment for energy content. Most buyers
will be aware of the volume and energy content of their purchases, and
because storage of natural gas is difficult, gas purchases will usually
equal gas consumption.

There are large variations in the composition of raw natural gas as
produced from the field. However, processing by gas treatment plants to
remove liquids and impurities, and the homogenizing effect of blending
multiple gas streams into the pipeline system, tend to make natural gas
sold to the end user a much more consistent product. For emissions
estimation purposes, most of the variation in composition can be
accounted for by estimating emissions based on energy content, rather
than volume at standard temperature and pressure.

Natural gas combustion scales from household water heaters and furnaces
to giant gas turbine power generation installations. Natural gas is also
widely used in the industrial sector, in such analytically complex
undertakings as cogeneration and chemical feedstock use. Cogeneration
accounting is discussed in Part F.

As with other fuels, estimates from continuous emissions monitors that
report carbon dioxide emissions under the supervision of a regulatory
agency are rated "A." Emissions estimated using measured natural gas
purchases or consumption volumes and actual or contractual heating
content, together with default carbon dioxide emission factors, are also
rated "A" because there is such little variation in the composition of
pipeline-quality natural gas fuels. Mass balance emissions using
measured natural gas volumes, but with assumed or default heating
values, is rated "B." Note that residential and commercial natural gas
bills usually provide the heating value of the gas sold.

Natural gas with extremely high or low heating values probably also has
an idiosyncratic chemical composition. Heating values greater than 1,100
Btu per standard cubic foot (scf)[^13] imply high levels of heavier
hydrocarbons such as propane or butane. Lower heating values imply high
levels of inert gases such as nitrogen or carbon dioxide. Reporters
using natural gas with a Btu content lower than 975 Btu per scf, or
higher than 1,100 Btu per scf, should avoid using a default emission
factor. To achieve an "A" rating for a mass balance estimate for gas
falling outside this range, the reporter should estimate emissions using
an emission factor based on an actual gas composition analysis (see
Table 1.C.4). A gas composition analysis is a listing of the major
component gases in a particular sample of natural gas, measured by molar
volume. Gas composition analyses might be done to determine heating
value, carbon content, or to verify compliance with contractual
composition.

###### Table 1.C.4. Rating of Estimation Methods for Carbon Dioxide Emissions from Natural Gas Combustion {#table-1.c.4.-rating-of-estimation-methods-for-carbon-dioxide-emissions-from-natural-gas-combustion .Heading6}

+----------------------------------------------------------------+-----+
| ######## Estimation Method                                     | *   |
|                                                                | *Ra |
|                                                                | tin |
|                                                                | g** |
+----------------------------------------------------------------+-----+
| Continuous emissions monitoring or mass balance supervised by  | A   |
| a regulatory agency                                            |     |
+----------------------------------------------------------------+-----+
| Mass balance where heating value is known and falls between    | A   |
| 975 and 1100 Btu per standard cubic foot.                      |     |
+----------------------------------------------------------------+-----+
| Mass balance where heating value and gas composition are known | A   |
| and used to calculate a situation-specific emission factor     |     |
| (even if outside 975-1100 Btu/scf range)                       |     |
+----------------------------------------------------------------+-----+
| Mass balance based on purchases where only volume is known (no | B   |
| heating value)                                                 |     |
+----------------------------------------------------------------+-----+
| Mass balance of "rich" flare gas, or low-Btu gas, where        | C   |
| composition is not known                                       |     |
+----------------------------------------------------------------+-----+

Table 1.C.5 provides default emission coefficients for pipeline quality
natural gas in the United States.

Table 1.C.5. Carbon Dioxide Emission Coefficients for U.S. Natural Gas
assuming 99.5 Percent Combusted

+-----------------------------+-------------------+-------------------+
| **HHV Btu Content per**     | **Emission        |                   |
|                             | Factor**          |                   |
| **Standard Cubic Foot**     |                   |                   |
|                             | **(metric tons    |                   |
|                             | carbon per        |                   |
|                             | billion Btu)**    |                   |
+-----------------------------+-------------------+-------------------+
|                             | **CO~2~**         | **Carbon**        |
+-----------------------------+-------------------+-------------------+
| 975 -- 1,000                | 53.74             | 14.66             |
+-----------------------------+-------------------+-------------------+
| 1,000 -- 1,025              | 52.65             | 14.36             |
+-----------------------------+-------------------+-------------------+
| 1,025 -- 1,050              | 52.79             | 14.40             |
+-----------------------------+-------------------+-------------------+
| 1,050 -- 1,075              | 52.93             | 14.51             |
+-----------------------------+-------------------+-------------------+
| 1,075 -- 1,100              | 53.18             | 14.50             |
+-----------------------------+-------------------+-------------------+

**Source**: Energy Information Administration, Documentation for
Emissions of Greenhouse Gases in the United States 2003, May 2005, Table
6-5, p. 194, web site:
www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

Natural gas is normally combusted completely in most of its
applications. A default of 99.5 percent combustion is used for the
emission factors in Table 1.C.5 and should be used in conjunction with
reporter-developed estimates of carbon content in natural gas consumed,
unless the reporter has information that would indicate a different
level.

##### 1.C.3.3 Middle Distillates and Heavy Fuel Oil

"Middle distillates" is a term used by oil refiners to mean refined
petroleum products that lie between gasoline and fuel oil. Distillates
are nearly pure hydrocarbons, with extremely low levels of impurities
such as sulfur or nitrogen. The most common distillate products are:

-   Diesel fuel (including variants such as railroad, high speed, and
    marine diesel).

-   No. 1 and No. 2 fuel oil (similar to diesel fuel, but not taxed in
    the United States).

-   Kerosene-based jet fuel in civilian (Jet A) and military (JP-8)
    variants.

-   Household kerosene, used for lighting and space heating.

-   Undifferentiated middle distillates used as petrochemical
    feedstocks.

Over the past thirty years, distillates have usually been significantly
more expensive than natural gas. This has resulted in the use of
distillates for stationary source combustion being concentrated
primarily in remote, rural, or temporary locations, or in holdovers from
the era of cheap petroleum in the 1960s. Nonetheless, numerous examples
remain of stationary source combustion using distillate fuel in the
United States, both large and small. Some of the more prominent examples
are:

-   Residential and commercial space heating using heating oil.

-   Stationary diesel engines driving electrical generators or providing
    motive power.

-   Gas turbines for power generation (typically peaking power),
    compression, or motive power.

Heavy fuel oil, also called residual oil, has historically been the
leftover heavy fraction of the crude oil barrel after the valuable light
products, including the distillates, have been extracted. As such, fuel
oil can have comparatively high sulfur contents---as much as 6 or 7
percent. In the United States, however, No. 5 and No. 6 fuel oil is
typically a low sulfur semi-synthetic product that is no longer really a
"residual." There can be considerable diversity in the actual density
and carbon content of heavy fuel oil, therefore, particularly when
comparing fuel oils used outside and within the United States.

Petroleum-burning installations are less likely to use continuous or
other forms of emissions monitoring because of their relatively small
size. Mass balance calculations will therefore usually be the only
feasible method to estimate carbon dioxide emissions from those sources.

Most distillates and fuel oils are sold by volume (i.e., per gallon or
barrel). Density, carbon content, and heating value do not normally form
part of their formal definition, nor are those characteristics usually
included as contractual elements in fuel purchase agreements. Hence,
neither sellers nor buyers are likely to possess the information they
need to calculate emissions based on the specific characteristics of the
fuel. In lieu of this, reporters should use the standard characteristics
shown in Table 1.C.6.

###### Table 1.C.6. Emission Factors and Other Default Characteristics for Distillates and Fuel Oils Used In Stationary Source Combustion, Assuming 99 Percent Combusted {#table-1.c.6.-emission-factors-and-other-default-characteristics-for-distillates-and-fuel-oils-used-in-stationary-source-combustion-assuming-99-percent-combusted .Heading6}

+------------------+--------+--------+-----------+---------+---------+
| **Fuel**         | **Em   |        | **Gross   | **De    | **      |
|                  | ission |        | Heat of   | nsity** | Percent |
|                  | Fa     |        | Com       |         | C       |
|                  | ctor** |        | bustion** | **(     | arbon** |
|                  |        |        |           | Barrels |         |
|                  | **(    |        | **(       | per     | **(by   |
|                  | Metric |        | Million** | Metric  | we      |
|                  | Tons** |        | **Btu per | Ton)**  | ight)** |
|                  |        |        | Barrel)** |         |         |
|                  | **per  |        |           |         |         |
|                  | 10^9^  |        |           |         |         |
|                  | HHV    |        |           |         |         |
|                  | Btu)** |        |           |         |         |
+------------------+--------+--------+-----------+---------+---------+
|                  | **C    | **Ca   |           |         |         |
|                  | O~2~** | rbon** |           |         |         |
+------------------+--------+--------+-----------+---------+---------+
| Middle           | 72.32  | 19.80  | 5.825     | 7.44    | 86.34   |
| Distillate Fuel  |        |        |           |         |         |
| (No. 1, No. 2,   |        |        |           |         |         |
| No. 4 fuel oil), |        |        |           |         |         |
| diesel, home     |        |        |           |         |         |
| heating oil      |        |        |           |         |         |
+------------------+--------+--------+-----------+---------+---------+
| Jet Fuel (Jet A, | 70.87  | 19.33  | 5.670     | 7.73    | 86.30   |
| JP-8)            |        |        |           |         |         |
+------------------+--------+--------+-----------+---------+---------+
| Kerosene         | 7      | 19.58  | 5.670     | 7.71    | 86.01   |
|                  | 1.2359 |        |           |         |         |
+------------------+--------+--------+-----------+---------+---------+
| Heavy Fuel Oil   | 78.80  | 21.49  | 6.287     | 6.34    | 85.68   |
| (No. 5, 6 fuel   |        |        |           |         |         |
| oil), bunker     |        |        |           |         |         |
| fuel             |        |        |           |         |         |
+------------------+--------+--------+-----------+---------+---------+

Source: Energy Information Administration, Documentation for Emissions
of Greenhouse Gases in the United States 2003, May 2005, Table 6-6, p.
200, web site:
www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

Table 1.C.7 lists the possible emission estimation approaches, in
increasing order of desirability. (Most reporters will have only
volumetric data).

###### Table 1.C.7. Default Emissions Factor Methods for Distillate and Fuel Oil Stationary Source Combustion {#table-1.c.7.-default-emissions-factor-methods-for-distillate-and-fuel-oil-stationary-source-combustion .Heading6}

  ----------------------------- -----------------------------------------
  **Information Available**     **Method**

  Volume Only                   Use assumed Btu content and emission
                                factor from Table 1.C.6

  Actual weight or volume +     Use or calculate weight of fuel, use
  actual density                default carbon content from Table 1.C.6,
                                assume 99 percent combusted

  Actual heating value (gross   Use emission factor from Table 1.C.6
  or net)                       

  Actual weight plus actual     Use actual weight multiplied by carbon
  carbon content                content, assume 99 percent combusted
  ----------------------------- -----------------------------------------

##### 1.C.3.4 Liquefied Petroleum Gases (LPG)

Unlike most hydrocarbon fuels, liquefied petroleum gases are nearly pure
compounds, comprising ethane (C~2~H~6~), propane (C~3~H~8~), and butane
(C~4~H~10~). Ethane is used widely as a petrochemical feedstock in the
United States, with some secondary fuel use; propane is a common
residential and commercial fuel for space heating use; and butane is
used primarily as a petrochemical feedstock. Table 1.C.8 shows ratings
for the various estimation methods.

###### Table 1.C.8. Rating of Estimation Methods for Carbon Dioxide Emissions from Fuel Oil and Liquid Petroleum Gas Combustion {#table-1.c.8.-rating-of-estimation-methods-for-carbon-dioxide-emissions-from-fuel-oil-and-liquid-petroleum-gas-combustion .Heading6}

+----------------------------------------------------------------+-----+
| **Estimation Method**                                          | *   |
|                                                                | *Ra |
|                                                                | tin |
|                                                                | g** |
+================================================================+=====+
| Fuel Oil                                                       | A   |
|                                                                |     |
| Continuous emissions monitoring (CEM) or mass balance          |     |
| supervised by a regulatory agency                              |     |
+----------------------------------------------------------------+-----+
| Mass balance based on actual\* fuel consumption and specific   | A   |
| information about fuel quality (e.g., heating value, density,  |     |
| or actual carbon content)                                      |     |
+----------------------------------------------------------------+-----+
| Mass balance based on actual\* fuel consumption (or purchases  | B   |
| if stock changes are not material\*\*), with default emission  |     |
| factors                                                        |     |
+----------------------------------------------------------------+-----+
| Mass balance based on fuel purchases (with no correction for   | C   |
| stock change, if material\*\*) and default emission factors    |     |
+----------------------------------------------------------------+-----+
| Liquid Petroleum Gas                                           | A   |
|                                                                |     |
| Continuous emissions monitoring (CEM)                          |     |
+----------------------------------------------------------------+-----+
| Mass balance using actual^\*^ quantities consumed (volume,     | A   |
| weight, or heating value), the actual product is known and is  |     |
| propane or butane                                              |     |
+----------------------------------------------------------------+-----+
| Mass balance using actual quantities consumed (volume, weight, | B   |
| or heating value), the actual LPG product is not known.        |     |
+----------------------------------------------------------------+-----+
| Mass balance using fuel purchase data (with no correction for  | C   |
| stock change, if material)                                     |     |
+----------------------------------------------------------------+-----+

\*Actual quantities may be based on measured fuel use, fuel purchases
corrected for stock changes, or uncorrected fuel purchase data where
stock changes are not material. Changes in stocks equal to or greater
than 5 percent of initial stocks are considered to be material.

\*\*Changes in stocks equal to or greater than 5 percent of initial
stocks are considered to be material.

In general, it is unlikely that LPG-burning stationary source combustion
installations will have continuous emissions monitors. Consequently,
emission estimation should be calculated through mass balance. The usual
uncertainty about the actual density and composition of the fuel will
not normally exist because LPGs are usually pure compounds, and default
emission factors should be highly accurate. Table 1.C.9 below provides
the default emission factors for the various LPG. If you are unable to
determine the specific LPG used, apply the default emission factor for
unspecified LPG.

###### Table 1.C.9. Emission Factors for Liquefied Petroleum Gases Assuming 99 Percent Combusted {#table-1.c.9.-emission-factors-for-liquefied-petroleum-gases-assuming-99-percent-combusted .Heading6}

+-----------+------+------+------------+----------------+------------+
| **Fuel**  | **   |      | **Gross    | **Density**    | **Percent  |
|           | Emis |      | Heat of    |                | Carbon**   |
|           | sion |      | Co         | **(Barrels per |            |
|           | Fact |      | mbustion** | Metric Ton)**  | **(by      |
|           | or** |      |            |                | weight)**  |
|           |      |      | **(MMBtu   |                |            |
|           | (me  |      | per        |                |            |
|           | tric |      | Barrel)**  |                |            |
|           | to   |      |            |                |            |
|           | ns/1 |      |            |                |            |
|           | 0^9^ |      |            |                |            |
|           | Btu) |      |            |                |            |
+-----------+------+------+------------+----------------+------------+
|           | *    | **   |            |                |            |
|           | *CO~ | Carb |            |                |            |
|           | 2~** | on** |            |                |            |
+-----------+------+------+------------+----------------+------------+
| Ethane    | 5    | 1    | 2.916      | 16.88          | 80.0       |
|           | 8.98 | 6.09 |            |                |            |
+-----------+------+------+------------+----------------+------------+
| Propane   | 6    | 1    | 3.824      | 12.44          | 81.8       |
|           | 2.44 | 7.03 |            |                |            |
+-----------+------+------+------------+----------------+------------+
| Isobutene | 6    | 1    | 4.162      | 11.20          | 82.8       |
|           | 4.43 | 7.57 |            |                |            |
+-----------+------+------+------------+----------------+------------+
| n-butane  | 6    | 1    | 4.328      | 10.79          | 82.8       |
|           | 4.32 | 7.54 |            |                |            |
+-----------+------+------+------------+----------------+------------+
| Un        | 6    | 1    | NA         | NA             | NA         |
| specified | 2.47 | 7.04 |            |                |            |
| LPG       |      |      |            |                |            |
+-----------+------+------+------------+----------------+------------+

**Source**: Energy Information Administration, Documentation for
Emissions of Greenhouse Gases in the United States 2003, May 2005, Table
6-9, p.207, web site:
www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

Carbon dioxide emissions estimates based on either mass, volume, or
energy calculations are rated "A" if the actual quantities consumed are
used, or if opportunities for storage are small (less then 10 percent of
annual purchases). Emissions estimates are rated "B" if fuel purchase
data are used and stocks are large (greater than 10 percent) relative to
annual volume consumed.

#### 1.C.4 Common Sources: Methane and Nitrous Oxide

Stationary source combustion units also emit trace amounts of methane
and nitrous oxide. While such emissions are rarely measured accurately,
available information suggests the amounts will usually be very small.
Some possible emissions estimation methods are:

-   Continuous emissions monitoring of methane and nitrous oxide. If
    there is an installed CEM that measures and reports methane or
    nitrous oxide emissions, this method would be rated "A" (such an
    installation would be highly unusual).[^14]

-   Unit-specific emission factors based on periodic or one-time exhaust
    sampling (e.g., from actual measurements) from the actual unit would
    be rated "A."

-   Default emission factors that are publicly documented and have been
    widely reviewed and adopted by a public agency, a standards-setting
    organization or an industry group (e.g., EIA's *Documentation for
    Emissions of Greenhouse Gases in the United States*, EPA's AP-42,
    the IPCC Guidelines, or the API Compendium) are rated "B."

-   Default emission factors based on other published sources are rated
    "C." See Table 1.C.10.

###### Table 1.C.10. Ratings for Methane and Nitrous Oxide Emissions from Stationary Source Combustion {#table-1.c.10.-ratings-for-methane-and-nitrous-oxide-emissions-from-stationary-source-combustion .Heading6}

  -------------------------------------------------------------- ------------
  **Computation Method**                                         **Rating**

  Continuous Emissions Monitor                                   A

  Fuel consumption measurements and unit-specific emission       A
  factors based on periodic, site-specific measurements          

                                                                 

  Fuel consumption measurements and default emission factors     B
  that are publicly documented and have been widely reviewed and 
  adopted by a public agency, a standards-setting organization   
  or an industry group                                           

  Fuel consumption measurements and default emission factors     C
  based on other published sources.                              

  Fuel consumption estimates and default emission factors based  D
  on other published sources.                                    
  -------------------------------------------------------------- ------------

There are three general sources for default emission factors for nitrous
oxide and methane produced from fossil fuel combustion. The EPA's AP-42
handbook contains factors for a limited range of combustion technologies
located throughout various chapters of the book.[^15] EPA periodically
updates the emission factors used in the AP-42 handbook as additional
information becomes available. Reporters should consult the AP-42
handbook and use the most current emission factor available at the time
of preparing their emissions estimate. The IPCC has two sets of methane
and nitrous oxide emission factors, one more detailed and
technology-specific, and one more generic. While more specific emission
factors are typically preferred over more general emission factors, the
rating for all three sources (AP-42 and the two IPCC factors) is "B

The IPCC generic listing is provided in Table 1.C.11 below.

###### Table 1.C.11. IPCC Generic Methane and Nitrous Oxide Emission Factors for Stationary Fuel Combustion {#table-1.c.11.-ipcc-generic-methane-and-nitrous-oxide-emission-factors-for-stationary-fuel-combustion .Heading6}

  ----------------------------- ----------------- -----------------------
  **Source**                    **Methane (kg     **Nitrous Oxide (kg per
                                /10^6^ Btu )**    10^6^ Btu)**

  Coal                                            

  Residential                   2.700             0.013

  Commercial                    0.090             0.013

  Industry                      0.090             0.013

  Electricity Generation        0.009             0.013

  Petroleum                                       

  Residential                   0.090             0.005

  Commercial                    0.090             0.005

  Industry                      0.018             0.005

  Electricity Generation        0.027             0.005

  Natural Gas                                     

  Residential                   0.043             0.000853

  Commercial                    0.043             0.000853

  Industry                      0.043             0.000853

  Electricity Generation        0.008             0.000853

  Wood                                            

  Residential                   2.70              0.036

  Commercial                    2.70              0.036

  Industry                      0.27              0.036

  Electricity Generation        0.27              0.036
  ----------------------------- ----------------- -----------------------

**Source**: Intergovernmental Panel on Climate Change, *Greenhouse Gas
Inventory Reference Manual* (Revised 1996 IPCC Guidelines for National
Greenhouse Gas Inventories)*,* p. 1-35.

Note: Converted from lower heating value metric units to higher heating
value Btu by DOE.

#### 1.C.5 Combustion from Special Situations

##### 1.C.5.1 Refinery Gas

Refinery gas accounts for about 5 percent of U.S. oil consumption.
Petroleum refiners boil or cook crude oil and other hydrocarbon
feedstocks at very high temperatures. Under the impact of the heat, some
of the hydrocarbon molecules disintegrate, releasing free hydrogen and
hydrocarbon gases such as methane or ethane. Carbon monoxide and carbon
dioxide may also be present. The blend will also contain smaller amounts
of vapor from heavier hydrocarbons. The resulting gas is simultaneously
a useful fuel, a potential feedstock, and an explosive safety hazard to
be controlled.

Refineries are typically designed to recycle refinery gas as a heating
fuel or (sometimes) a refinery feedstock. If processes generate refinery
gas in excess of fuel and/or feedstock needs, refinery gas may be
flared, or used to provide pilot lights for refinery flares. There are
also a few cases where U.S. refinery gas is upgraded and exported as
pipeline-quality natural gas to the interstate pipeline system.

The difficulties associated with estimating refinery gas emissions for
inventory purposes are twofold:

-   As an internal byproduct, refinery gas quantities are not always
    measured accurately, particularly if the gas is flared. Information
    about the volume of gas produced and its disposition may be held by
    plant operators and never appear in corporate accounting data.

-   Even if the volume of refinery gas is known, its chemical
    composition is often highly variable because for large refineries
    the product is a blend of outgases in constantly varying quantities
    from a selection of refinery units. The average composition of
    refinery gas at a particular location will depend on which units and
    what feedstocks are being run at each particular moment in time.
    Refinery gas therefore includes varying quantities of
    high-carbon-per-Btu methane and no-carbon-per-Btu hydrogen.

Two default emission factors for refinery gas are available. The factor
used by the Energy Information Administration (EIA) for its national
emissions inventory is 17.51 metric tons carbon/billion Btu (higher
heating value). It is based on an average of a small number of samples
from the early 1990s.[^16]

An alternative default factor has been proposed by the American
Petroleum Institute's (API) Greenhouse Gas Compendium: 0.0567 metric
tons carbon dioxide per million Btu, equivalent to 15.45 metric tons
carbon per billion Btu, citing "internal company information" as a
source.[^17] Note that API's coefficient is about 12 percent lower than
EIA's coefficient (presumably because API's sample has more hydrogen and
less carbon monoxide, ethane, and propane than EIA's small set of
samples).

Reporters should use the EIA factor (17.42 metric tons carbon per
billion Btu) as a default emission coefficient if no better information
is available because its coefficient, which is for still gas, most
closely approximates that gas mixture use as a feedstock (the principal
constituents are methane, ethane, ethylene, normal butane, butylene,
propane, and propylene). Reporters, however, should use available
product-specific information, if reliable, in preference to a default
factor. Ratings for various computation methods are provided in Table
1.C.12.

###### Table 1.C.12. Ratings for Carbon Dioxide Emissions from Refinery Fuel Gas {#table-1.c.12.-ratings-for-carbon-dioxide-emissions-from-refinery-fuel-gas .Heading6}

  -----------------------------------------------------------------------------
  **Information Available**                                        **Rating**
  ---------------------------------------------------------------- ------------
  Continuous emissions monitoring (or mass balance), supervised by A
  a regulatory agency                                              

  Mass balance, based on measured volume and density and           A
  composition from multiple gas samples                            

  Mass balance, based on measured volume and density, and          B
  composition from a single gas sample                             

  Mass balance, based on measured heat content, and a default      B
  emission factor that is publicly documented and has been widely  
  reviewed and adopted by a public agency, a standards-setting     
  organization or an industry group                                

  Mass balance, based on measured heat content, using other        C
  default emission factor                                          

  Mass balance, based on volume, using assumed heating value and   D
  default emission factor                                          
  -----------------------------------------------------------------------------

The default factors provided above assume 100 percent combustion.
However, reporters should reduce these factors by the estimated fraction
combusted, which should be assumed to be 98 percent for flaring and 99
percent for combustion as a boiler fuel. Reporters should note that both
fuel use and flaring result in carbon dioxide emissions, and should make
estimates that encompass both uses.

##### 1.C.5.2 Petroleum Coke

Petroleum coke is a solid fuel composed of 90 percent or more carbon,
and is usually created as a byproduct of the intensive refining of heavy
oil feedstocks. It is similar to a high-grade coal, and EIA statistics
describe it as catalyst coke and as marketable coke. Marketable coke is
produced by oil refineries and sold as a commercial fuel or burned
on-site as a fuel. Catalyst coke typically accumulates within oil
processing units and is combusted in situ or removed and combusted.

Refiners may experience difficulty in estimating combustion usage of
catalyst coke because it is not sold and may not be combusted for fuel
purposes. A proper accounting for refinery sector emissions should,
however, include accounting for all carbon oxidized into carbon dioxide
from refinery sources, and this will necessarily include estimates of
emissions from the combustion of catalyst coke. Ratings for coke
emissions estimations are provided in Table 1.C.13.

###### Table 1.C.13. Ratings for Carbon Dioxide Emissions from Petroleum Coke. {#table-1.c.13.-ratings-for-carbon-dioxide-emissions-from-petroleum-coke. .Heading6}

  ---------------------------------------------------------------- ------------
  **Information Available**                                        **Rating**

  Continuous emissions monitoring or mass balance supervised by a  A
  regulatory agency                                                

  Mass balance based on measured consumption or complete estimate  A
  of usage (including catalyst coke and non-fuel use, if           
  applicable), actual carbon content composition of coke based on  
  periodic samples                                                 

  Mass balance based on measured consumption or complete estimate  B
  of usage (including catalyst coke and non-fuel use, if           
  applicable), actual carbon content based on one-time sample      

  Mass balance based on measured consumption or complete estimate  B
  of usage, plus a default emission factor that is publicly        
  documented and has been widely reviewed and adopted by a public  
  agency, a standards-setting organization or an industry group    

  Mass balance based on measured consumption or complete estimate  C
  of usage, plus other default emission factor                     

  Mass balance based on marketable coke only (if catalyst coke is  D
  being combusted) and default emission factor                     
  ---------------------------------------------------------------- ------------

Petroleum coke is used as a commercial fuel by refiners themselves, by
electricity generators, and by cement producers in the United States. In
these roles, petroleum coke should be treated in a manner analogous to
coal, though using a petroleum coke emission coefficient.

Petroleum coke is also used as a carbon source in several industrial
processes, notably as a sacrificial anode in aluminum smelting and a
reducing agent in some metal refining processes. To the extent that the
non-combustion use of petroleum coke results in the coke being oxidized,
reporters should calculate emissions based on mass balance and the
fraction combusted, even though technically the coke is not being used
as fuel.

##### 1.C.5.3 Flaring of Natural Gas or Crude Oil

Venting and flaring of commercial petroleum fuels is relatively uncommon
but does occur, particularly in remote areas where natural gas cannot be
marketed. Some of the more common circumstance under which flaring or
venting may occur are:

-   Flaring of waste or "off-spec" gas by gas processing plants.

-   Safety flaring during process upsets in gas treatment, petroleum
    refining, or chemical plants; or as "pilot lights" on safety flares.

-   Production testing on exploration wells (oil or gas).

-   Flaring of unmarketable natural gas in remote areas.

Reporters should include any venting or flaring of natural gas and/or
crude oil in their inventory. There are, however, certain complexities
associated with estimating emissions from this source. Those include:

-   Venting and flaring is not always measured, nor measured accurately.
    An "accurate" method for the purposes of this program is defined as
    a flow meter. Calculations based on reservoir balances, gas-oil
    ratios, or using lasers, are deemed "estimated."

-   Venting natural gas implies methane emissions, which should be
    calculated by taking a compositional analysis of the raw natural gas
    and directly calculating methane (and carbon dioxide) emissions from
    the composition of the source gas.

```{=html}
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```
-   If the flare has relatively low combustion efficiency, the
    combustion implies methane emissions for the uncombusted portion of
    the flare.

Emissions from flare gas may be materially different than emissions of
pipeline quality natural gas. Untreated raw "associated" natural gas
produced in conjunction with crude oil will normally have high levels of
propane and butane compared with pipeline gas. Raw natural gas will also
occasionally have high levels of natural carbon dioxide (for instance,
in parts of Texas and in Indonesia). In all cases, accurate estimates
can be derived by calculating an emission factor based on the
composition of a sample of the actual natural gas being flared.

Crude oil flaring is even more unusual than natural gas flaring, but
does occur. In some parts of the world crude oil has also been used as a
convenient oilfield boiler fuel (e.g., for steam floods). The most
accurate emissions estimate in this case should be obtained by
calculated carbon content from an ultimate analysis of the crude oil. If
an ultimate analysis is not available, a tolerable proxy can be obtained
when density and sulfur content are known, by assuming that carbon
accounts for 85 percent of the non-sulfur portion of the crude oil
(i.e., carbon content = (0.85 \* (1-sulfur content)). If the reporter
does not know density, a default emission factor can be obtained from
EIA based on typical densities and heating values: 20.10 mtC (73.69
mtCO~2~) per 10^6^ HHV Btu assuming 99 percent combustion.[^18] Ratings
for venting and flaring of natural gas emissions along with the rare
cases when crude oil is combusted are shown in Table 1.C.14.

###### Table 1.C.14. Carbon Dioxide Emissions Ratings for Venting and Flaring of Natural Gas and Combustion of Crude Oil {#table-1.c.14.-carbon-dioxide-emissions-ratings-for-venting-and-flaring-of-natural-gas-and-combustion-of-crude-oil .Heading6}

+-------------------------------------------------------------+--------+
| **Computation Method**                                      | **Ra   |
|                                                             | ting** |
+-------------------------------------------------------------+--------+
| **Venting and Flaring of Natural Gas**                      | A      |
|                                                             |        |
| Measured venting or flaring; actual composition data from   |        |
| periodic samples                                            |        |
+-------------------------------------------------------------+--------+
| Measured venting or flaring; actual composition data from   | B      |
| single sample                                               |        |
+-------------------------------------------------------------+--------+
| Measured venting or flaring; assumed composition using a    | B      |
| published default emission factor that is publicly          |        |
| documented and has been widely reviewed and adopted by a    |        |
| public agency, a standards-setting organization or an       |        |
| industry group                                              |        |
+-------------------------------------------------------------+--------+
| Estimated venting or flaring; assumed composition using     | C      |
| other default emission factors                              |        |
+-------------------------------------------------------------+--------+
| **Crude Oil Combustion**                                    | A      |
|                                                             |        |
| Measured fuel use; emission factor based on actual          |        |
| composition data from periodic samples                      |        |
+-------------------------------------------------------------+--------+
| Measured fuel use; assumed composition using a published    | B      |
| default emission factor that is publicly documented and has |        |
| been widely reviewed and adopted by a public agency, a      |        |
| standards-setting organization or an industry group         |        |
+-------------------------------------------------------------+--------+
| Estimated fuel use; emission factor based on actual         | C      |
| composition data from single sample                         |        |
+-------------------------------------------------------------+--------+
| Estimated fuel use; assumed composition using default       | D      |
| emission factor                                             |        |
+-------------------------------------------------------------+--------+

##### 1.C.5.4 Petroleum-Based Waste and Byproduct Fuels

Reporters may also combust a range of specialized waste and byproduct
fuels. Those might include:

-   Used lubricants, especially motor oil.

-   Used tires or tire-derived fuel.

These waste fuels are often burned in conjunction (co-fired) with more
conventional fuels. If emissions are estimated based on continuous
emissions monitoring, the monitor will measure carbon dioxide emissions
from whatever combination of fuels is actually burned. In general,
burning petroleum-based waste fuels raises no special issues.

If emissions are estimated based upon mass balance calculations, the
reporter will need to have information about the quantity and
composition of the fuels burned. Reporters are unlikely, though, to have
specific information about the quality and composition of waste fuels,
beyond a measure of the weight, volume, and hopefully the heating value
of the fuel. In general, default emission factors will need to be used
to cover these sources. See Table 1.C.15 below.

###### Table 1.C.15. Emission Factors for Selected Petroleum-Based Waste Fuels {#table-1.c.15.-emission-factors-for-selected-petroleum-based-waste-fuels .Heading6}

  ----------------------- ----------------------- -----------------------
  **Fuel**                **Density**             **Emission Factor**

  Waste Oil               ?                       9,979 kg CO~2~/gallon

  Tires/Tire-Derived Fuel 12,000-15,000 Btu/Lb.   85.8 metric tons
                                                  CO~2~/10^6^ Btu
  ----------------------- ----------------------- -----------------------

Source: Energy Information Administration, Instructions for Form
EIA-1605, Voluntary Reporting of Greenhouse Gases Program, Appendix B,
web site: www.eia.doe.gov/oiaf/1605/coefficients.html.

Table 1.C.16 specifies the ratings used for petroleum-based waste and
byproduct fuels.

###### Table 1.C.16. Ratings for Carbon Dioxide Emissions from Selected Petroleum-Based Waste Fuels {#table-1.c.16.-ratings-for-carbon-dioxide-emissions-from-selected-petroleum-based-waste-fuels .Heading6}

  -------------------------------------------------------------- ------------
  **Computation Method**                                         **Rating**

  Continuous emissions monitoring or mass balance supervised by  A
  a regulatory agency                                            

  Measured fuel use; emission factor based on actual composition A
  data                                                           

  Measured fuel use; assumed composition using default emission  B
  factor that is publicly documented and has been widely         
  reviewed and adopted by a public agency, a standards-setting   
  organization or an industry group                              

  Estimated fuel use; emission factor based on actual            C
  composition data                                               

  Estimated fuel use; assumed composition using default emission D
  factor                                                         
  -------------------------------------------------------------- ------------

##### 1.C.5.5 Biogenic Fuels (Bagasse, Wood, Wood Waste, and Ethanol)

Biogenic fuels are widely used, including wood burned in residences,
wood pellets, wood waste and black liquor used in the pulp and paper
industry, bagasse burned in sugar mills, wood shavings from lumber
yards, and municipal greenwaste. All biogenic fuels contain a
significant fraction of carbon, which is oxidized when burned. By
accounting convention, though, carbon dioxide emissions of biogenic
fuels do not "count" as anthropogenic emissions under the Framework
Convention on Climate Change because the carbon embedded in biogenic
fuels is presumed to form part of the natural carbon cycle. Carbon
dioxide emissions from the combustion of biomass fuel, including
discarded forest products, should not be included in either direct or
indirect emissions and their quantity should not be included in
combination with any other emissions category nor appear in totals or
net quantities. Carbon dioxide emissions from the non-combustion
oxidation of biomass, such as forest floor litter, biomass products, or
discarded forest products such as mill shavings, are similarly
considered carbon neutral.

Methane and nitrous oxide emissions from biogenic fuels are considered
anthropogenic, however, and low- temperature combustion of biogenic
fuels can produce large volumes of methane. Reporters combusting
biogenic fuels should therefore consider methane and nitrous oxide
emissions from this source.

Methane and nitrous oxide emissions are generally a product of
low-temperature combustion. Methane is favored by conditions of
incomplete combustion, where the organic compounds present in the fuel
are broken down by heat into simple hydrocarbons, including methane, but
there is insufficient heat or oxygen to combust them into carbon
dioxide. This may be a good working description of a residential
fireplace, but any process in which organic materials are burned may be
considered a potential candidate for methane emission sources.

Reporters should use the same ratings for nitrous oxide and methane
emissions from biogenic fuels as other fuels (shown on Table 1.C.10
above). In common with other sources of methane and nitrous oxide
emissions, emissions derived from continuous monitoring of the exhaust
stream or based on emission factors derived from periodic measurement of
the actual source exhaust stream would be rated "A." Emissions estimated
using a measurement or group of measurements of the actual exhaust
stream would be rated "B." Emissions estimated using default emission
factors would be rated "C."

Default emission factors may be derived from the EPA's AP-42 handbook or
from the IPCC Revised Guidelines. Some typical factors drawn from the
AP-42 handbook are shown in Table 1.C.17.

###### Table 1.C.17. Methane and Nitrous Oxide Emission Factors for Biogenic Fuel Sources {#table-1.c.17.-methane-and-nitrous-oxide-emission-factors-for-biogenic-fuel-sources .Heading6}

  ------------------------------- ---------------------- ----------------
  **Source**                      **Methane**            **Nitrous
                                                         Oxide**

  Wood residue (industrial)       95.3 kg / 10^6^ Btu    NA
                                  residue                

  Conventional wood stove         15 kg / metric ton     NA
  (non-catalytic)                 wood                   

  Wood stove (non-catalytic)      8 kg / metric ton wood NA

  Wood stove (catalytic)          5.8 kg / metric ton    NA
                                  wood                   

  Residential fireplace           NA                     0.15 kg /metric
                                                         ton

  Charcoal manufacture            55 kg / metric ton     NA
                                  charcoal               
  ------------------------------- ---------------------- ----------------

**Source**: Environmental Protection Agency, *Compilation of Air
Pollutant Emission Factors* (AP-42), Fifth Edition, Volume I: Stationary
Point and Area Sources.

NA=not available.

##### 1.C.5.6 Municipal Solid Waste and Landfill Gas

Municipal solid waste is transmuted into an energy source by two
mechanisms:

-   It may be combusted directly (occasionally for disposal, more
    commonly as an energy source).

-   When buried in a landfill, it may decompose anaerobically (in the
    absence of oxygen) into landfill gas (approximately 50 percent
    methane and 50 percent carbon dioxide and water vapor by volume),
    which may be emitted to the atmosphere, flared, or combusted as a
    commercial energy source.

The treatment of municipal solid waste intersects with the treatment of
fuels from biogenic sources. From the point of view of emissions
accounting, only combustible material that contains carbon produces
carbon dioxide emissions. Only if this material is of anthropogenic
origin (e.g., plastics) does its combustion produce reportable carbon
dioxide emissions.

Reporters that combust municipal solid waste should thus examine
estimates of the composition of their waste stream, identify the
"anthropogenic carbon" (largely plastic and other synthetic materials)
share of the waste stream, and derive an emission factor based on the
anthropogenic carbon contained in each ton of municipal solid waste
combusted. If the waste combustion plant is subject to emissions
monitoring, the reported carbon dioxide emissions should be pro-rated by
a calculated anthropogenic share of the carbon based on the calculation
above.

If plant-specific estimates of the composition of the waste stream are
not available, reporters may use a default emission coefficient
developed by the EIA for use in the United States, based on earlier
research by the EPA, which indicated that the U.S. national waste stream
was 16 percent plastics, with an average emission coefficient of 5,771
lbs. carbon dioxide per short ton of plastic (2,885.5 kg/metric ton).
This is equivalent to 919 lbs. CO~2~ per short ton of municipal solid
waste, or 92 lbs. CO~2~ per million Btu (assuming a municipal solid
waste energy content of 5,000 Btu per lb.)[^19]

An emissions estimate using actual calculations from the waste stream
linked to continuous emissions monitoring under the supervision of a
regulatory agency would be rated "A." An emissions estimate using
default calculations from the waste stream, but pro-rating CEM data,
would be rated "B." An estimate using actual calculations from a
measured waste stream, linked to the quantity of waste combusted, would
also be rated "B." An estimate using the default emission factor
multiplied by the quantity of waste combusted would be rated "C."

###### Table 1.C.18. Ratings for Carbon Dioxide Emissions from Waste Fuels {#table-1.c.18.-ratings-for-carbon-dioxide-emissions-from-waste-fuels .Heading6}

  -------------------------------------------------------------- ------------
  **Computation Method**                                         **Rating**

  Continuous emissions monitoring or mass balance supervised by  A
  a regulatory agency; pro-rated by measured waste composition.  

  Continuous emissions monitoring or mass balance supervised by  B
  a regulatory agency, pro-rated by default waste composition.   

  Measured quantity of waste combusted multiplied by a default   B
  emission factor that is publicly documented and has been       
  widely reviewed and adopted by a public agency, a              
  standards-setting organization or an industry group            

  Measured quantity of waste combusted times other default       C
  emission factor                                                
  -------------------------------------------------------------- ------------

Non-combustion emissions of landfill gas and related issues are covered
in Part E, "Industrial Processes."

#### 1.C.6 Special Situations: Nonfuel Use of Fossil Fuels

There are a number of situations where fossil fuels are not combusted
directly, but are used for an industrial purpose. Those uses include:

-   Lubricants, asphalt, and petroleum-based solvents.

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```
-   Natural gas, LPG, and petroleum products as chemical feedstocks.

-   Coke and related products as reducing agents in metals manufacture.

-   Fossil fuels as a carbon source in products (e.g. carbon black).

-   Transformation of lower value hydrocarbon into a higher value
    hydrocarbon (synthetic fuels).

While the treatment of specific industrial processes is largely the
province of Part E, this section provides general guidance on the
treatment of non-fuel uses of fossil fuels.

Generally it is the reporter's responsibility to identify all emissions
of carbon dioxide that occur from facilities owned or controlled by the
reporter. When fossil fuels are used for nonfuel uses, the reporter
should identify whether the nonfuel use is sequestering,
non-sequestering, or partially sequestering. In a sequestering use, the
carbon in the feedstock remains in the final product or a waste stream,
and is sold or transferred by the reporter to another entity. In
non-sequestering use, the carbon in the final product is oxidized and
moves into the atmosphere. In a partially sequestering use, some carbon
is emitted to the atmosphere as carbon dioxide, while a portion remains
embedded in the product.

Most plastics manufacturing (e.g., ethane to ethylene to polyethylene)
appears to be largely sequestering. The carbon in the feedstock is
embedded in the product and is transferred by the chemical manufacturer
to another entity. Alternatively, certain forms of chemical
manufacturing (e.g., ammonia and hydrogen production) are
non-sequestering; i.e., a feedstock (usually methane) is reformed into a
carbon monoxide and hydrogen synthesis gas. The hydrogen is separated
from the carbon monoxide and further processed (into ammonia, for
instance), while the carbon monoxide is oxidized into carbon dioxide and
usually discarded.

The use of coal or coke as a reduction agent is similarly
non-sequestering. The coke is combusted under oxygen-deficient
conditions to generate carbon monoxide, which is then used to scrub
oxygen from metal ores. The resulting carbon dioxide is emitted to the
atmosphere.

Some processes are partially sequestering. The manufacture of carbon
black, for example, produces appreciable amounts of product composed
largely of mineral carbon, but also produces significant emissions of
carbon dioxide and carbon monoxide.

In each case it is the reporter's responsibility to understand the mass
balance of his or her industrial process, to determine the quantity of
carbon flowing through the reporter's entity, and ascertain how much
carbon was emitted into the atmosphere and how much was transferred in
product or in waste streams. Carbon emitted to the atmosphere is
generally a reportable emission, while carbon that is transferred in
product or in a waste stream is not reportable.

A computation of the carbon flows through an industrial process is also
called a "material balance" calculation. A material balance calculation
requires measuring or estimating the quantity of feedstock used in an
industrial process, the quantity of product manufactured, and the
quantity of materials discarded into waste streams, including
atmospheric emissions. This particular application of material balance
requires calculating the amount of carbon in the input feedstock, and
tracing the fate of that carbon as it flows into manufactured product
and waste streams. The material balance is an accounting of the sources
and disposition of carbon, which in principle should be equal.

To accurately calculate a material balance, the reporter must know how
much carbon is in the feedstock, how much carbon is in the manufactured
product, and what happens to the remaining amount, possibly through
stoichimetric calculations. A simpler procedure is to take the quantity
of feedstock purchased and multiply it by a default emission factor and
a default fraction not sequestered. This procedure is appropriate for
specialized processes where computing a material balance is meaningless
(e.g., use of asphalt, lubricants, or solvents), or where the source is
too small to make detailed material balance calculations worthwhile.

Generalized emission measurement ratings for non-fuel use of petroleum
products are shown below in Table 1.C.19.

###### Table 1C.19. Ratings for Carbon Dioxide Emissions from Non-Fuel Use of Fossil Fuel {#table-1c.19.-ratings-for-carbon-dioxide-emissions-from-non-fuel-use-of-fossil-fuel .Heading6}

  -------------------------------------------------------------- ------------
  **Computation Method**                                         **Rating**

  Facility-level mass balance computation with known product     A
  composition                                                    

  Facility-level mass balance computation with default emission  B
  factor for product                                             

  Product consumption multiplied by default emission factor      B
  multiplied by a default fraction combustion for asphalt,       
  lubricants, and solvents                                       

  Product consumption multiplied by default emission factor      C
  multiplied by default fraction sequestered (petrochemical      
  feedstocks).                                                   
  -------------------------------------------------------------- ------------

**Technical Guidelines for Voluntary Reporting of Greenhouse Gases
Program**

**Chapter 1, Emission Inventories**

### Part D: Mobile Sources

Outline

1.  Overview

2\. Estimation Methods

> 2.1. Overview
>
> 2.2. Mass Balance

3.  Inference

> 3\. Application and Ranking of Methods
>
> 3.1. Carbon Dioxide from Mobile Combustion Systems
>
> 3.2. Methane and Nitrous Oxide from Mobile Combustion Systems

3.  Hydrofluorocarbons from Mobile Refrigeration and Air Conditioning

> 4\. Special Situations:
>
> 4.1. Electric, Fuel Cell, and Bio-Fueled Vehicles

**Technical Guidelines Chapter 1, Part D: Mobile Sources**

#### 1.D.1 Overview

This part of Chapter 1 describes and rates methods of estimating
emissions of greenhouse gases from mobile sources, such as automobiles,
tractors, locomotives, watercraft, and aircraft. Mobile source
greenhouse gas emissions include carbon dioxide (CO~2~), methane
(CH~4~), and nitrous oxide (N~2~O) from fuel combustion, and
hydrofluorocarbons (HFC) from mobile air conditioning and refrigeration
system leakage. Generally, reporters can expect carbon dioxide to be the
largest portion of global warming potential (GWP)-weighted emissions
from mobile sources. Methane and nitrous oxide emissions account for a
relatively small fraction of overall mobile source greenhouse gas
emissions: approximately one to two percent combined for mobile sources
other than highway vehicles, and approximately five percent for
light-duty, on-road vehicles (e.g., passenger cars and light
trucks).[^20]

There are a range of special situations that are unlikely to be of
importance to reporters generally, but may be significant for particular
reporters. These include electric, fuel cell, and bio-fueled vehicles,
and they are discussed at the end of Part D.

Carbon dioxide emissions from the combustion of commercial fossil fuels
may be accurately measured by mass balance when properly applied.
Emissions of methane and nitrous oxide from combustion are difficult to
measure accurately, but established estimation methods, such as the use
of default emissions factors with vehicle distance traveled data, are
available to reporters. For hydrofluorocarbons, reporters estimate
emissions using inventories of refrigerant at installation, service, and
disposal of air conditioning and refrigeration systems.

#### 1.D.2 Estimation Methods

##### 1.D.2.1 Overview

Most mobile source emissions originate from combustion of commercial
fossil fuels, such as diesel fuel, gasoline, jet fuel, and residual fuel
oils. Carbon dioxide emissions depend primarily on the carbon content of
the fuel and the amount of fuel consumed. Methane and nitrous oxide
emissions are generally a function of the emissions control equipment
used (e.g., type of catalytic converter), and are also affected by the
efficiency and design of the combustion technology and the level of
operation and maintenance. More specifically, methane emissions from
motor vehicles are a function of the amount of hydrocarbons passing
uncombusted through the engine, and any post-combustion control of
hydrocarbon emissions, such as catalytic converters.[^21]

Nitrous oxide is specifically produced during the reaction of nitrogen
oxide (NO) and ammonia (NH~3~) over the platinum in the catalytic
converter, and therefore nitrous oxide emissions are generally greater
from vehicles with catalytic converter systems than from vehicles
without such controls, and greater from aged catalysts than from new
catalysts.[^22] Due to these complex interactions, there is greater
uncertainty associated with estimates of methane and nitrous oxide
emissions from mobile combustion sources relative to carbon dioxide
emissions estimates.[^23]

In addition to emissions from combustion of fuels, mobile sources
equipped with air conditioning or refrigeration systems also release
hydrofluorocarbons through leaks in the equipment. These gases may also
be released during installation, maintenance, and disposal of the
systems. As noted, release of hydrofluorocarbons from individual
vehicles may be small, but considering that their GWPs are hundreds or
even thousands of times greater than that of other mobile source
greenhouse gases, the effects of total hydrofluorocarbon emissions are
potentially significant.

For mobile sources, the mass balance method is most frequently used for
estimating carbon dioxide and hydrofluorocarbon emissions based on fuel
combustion and refrigerant use, respectively. Methane and nitrous oxide
emissions are commonly estimated by inference using activity data (e.g.,
distance traveled or fuel consumption) with emissions factors developed
from sample emissions measurement. For estimating carbon dioxide, mass
balance can produce accurate results if calculations are based on known
fuel properties such as weight and carbon content. Inferred emissions
can generally be expected to be less accurate, but are acceptable for
estimating minor emissions from methane and nitrous oxide. For leakage,
the mass balance method or inference may be used to estimate
hydrofluorocarbon emissions.

[]{.mark}

##### 1.D.2.2 Mass Balance

The mass balance method is based on the premise that the mass and energy
content of all components of a substance that go into a process must be
chemically accounted for in some form as output. Estimating emissions
using the mass balance method requires knowledge of the specific
chemical reaction and data on the quantity of raw materials used or
product manufactured. This information is used to estimate the mass of
materials from at least one part of the overall chemical reaction.
Emissions can then be calculated using the known molecular proportions
(stoichiometric ratios) of the reaction formula.

Carbon dioxide emissions can usually be computed to an accuracy of 5
percent or better by using the following general formula for mass
balance:[^24]

**C = QF \* CC \* FC\
**

**Where:**

**C = carbon dioxide emissions (metric tons)**

> **QF = quantity of fuel (measured in weight, volume, or heating
> value)**
>
> **CC = carbon coefficient (a ratio, metric tons carbon dioxide per
> "unit" of fuel, as above)**

**FC = fraction combusted**

Fuel quantity may be expressed in terms of weight (tons or pounds of
fuel); volume (barrels or gallons or cubic feet or cubic meters of
fuel); or heating value (million Btu or joules, either higher heating
value or lower heating value).[^25] The carbon coefficient of the fuel
is the theoretical maximum carbon dioxide emission rate for a fuel
expressed in terms of units of carbon dioxide per unit of fuel
denominated by any of these measures. If the carbon content of the fuel
is known, its carbon coefficient can be calculated by assuming 100
percent of the carbon is converted to carbon dioxide during combustion.
As recommended by the Intergovernmental Panel on Climate Change (IPCC),
reporters should use 99 percent as the factor for the fraction combusted
for all petroleum-based transportation fuels. For natural gas or other
gaseous fuels, reporters should use 99.5 percent as the factor for the
fraction combusted.[^26]

The default carbon dioxide emissions factors provided in this chapter
reflect the default carbon coefficients for the referenced fuel
multiplied by the IPCC recommended fraction combusted. Because reporters
will most often have data on consumption of liquid fuels in units of
volume, default emissions factors are presented below per unit of heat
content and per unit of volume.

In general, reporters should use the measure of fuel quantity that most
accurately represents the characteristics of the fuel consumed and
should minimize the use of default values by substituting parameters
based on measurements whenever possible.

When the actual carbon content of the fuel is known (based on a fuel
sample analysis), the most accurate calculation of mass balance
emissions is based on weight. If the reporter does not know the carbon
content of the fuel, but does know the heating value (this would be
typical of natural gas and some fuel oils), the most accurate mass
balance calculation would be based on heating value and a default
emissions factor.

Reporters will rarely have access, however, to detailed information
about the composition of transportation fuels. Transportation fuels are
predominantly composed of liquid fuels, which are generally sold by
volume, and are defined by specifications that do not normally address
heating value, carbon content, or density. Further, because
transportation fuels will often be purchased by the fuel tank-full in
diverse locations, a fuel-testing program will rarely be practicable.
For those reasons, the most accurate approach that is practically
achievable will usually be to multiply fuel volume by an assumed density
and carbon content per ton, or alternatively, to multiply fuel volume by
an assumed heating value per unit volume and an emissions factor
expressed per unit of heating value. Both approaches provide reasonably
accurate results, though not as accurate as when actual heating value or
density is known.

Fugitive emissions are most easily measured when a known quantity of gas
is purchased to replace losses that have occurred over a given time
period. Purchasing refrigerant to re-fill a refrigerating unit is an
example of this situation. In these cases, fugitive emissions are equal
to new purchases/inputs minus the volume of gas required to satisfy net
growth in the equipment stock (net growth equals the difference between
the volumes of new and retiring equipment). This type of estimation
falls under the category of mass balance, because it tracks specific
quantities of materials included in a process.

##### 1.D.2.3 Inference

The inference method is the use of emissions factors derived from sample
data of prior observations that are assumed to be representative of
certain conditions that will be experienced by other reporters. Because
mass balance estimates are irrelevant to emissions of methane and
nitrous oxide (as well as criteria pollutants), emissions estimates must
either be made directly, from observed emissions, or indirectly by
inference from prior direct observation, either of the unit in question,
or of some comparable unit. Nitrous oxide and methane emissions depend
largely on combustion technology type and vintage, emission control
technology, maintenance, and operational practices. Emissions of those
gases are only generally related to fuel consumption or vehicle distance
traveled.

Unfortunately, there is insufficient information to establish a useful
relationship between many of the specifics of vehicle characteristics or
operating cycles and emissions. Even if such information existed,
reporters would find difficulty in obtaining this information about
their vehicle fleets. Fortunately, available information suggests that
nitrous oxide and methane emissions from mobile sources will normally be
small.

Estimates should be based on vehicle distance traveled data and
emissions factors for the specific vehicle types and technology,
whenever possible. If vehicle distance traveled data is unavailable,
fuel consumption data together with fuel economy factors can be used to
back-calculate vehicle distance traveled. Information on specific
emission control technologies, such as catalytic converters, may be
inferred from weighted averages of control technologies by vehicle model
year.

The IPCC, World Resources Institute/World Business Council for
Sustainable Development (WRI/WBCSD), U.S. Environmental Protection
Agency (EPA), Energy Information Administration (EIA), American
Petroleum Institute (API), and other authorities on greenhouse gas
estimation methods provide inference-based methods to estimate emissions
associated with methane and nitrous oxide emissions from mobile sources.
These equations use activity-level data and an associated emissions
factor, according to the following general formula:

**E = AL \* EF**

**Where:**

**E = Emission**

**AL = Activity Level**

**EF = Emissions Factor.**

The EPA's *Inventory of U.S. Greenhouse Gas Emissions and Sinks*
contains U.S. transportation sector-specific emissions factors.[^27]
Emissions factors are provided by type of highway vehicles (e.g.,
passenger cars, light and heavy duty trucks, motorcycles, etc.) and
control technology (e.g., specific types of catalytic converters and
without catalytic converters). Because data on specific vehicle fleet
technologies may not be available, a more generalized set of emissions
factors using a weighted average of control technologies by vehicle
model year also is available.[^28]

Methane and nitrous oxide emissions from mobile sources have not been
extensively studied and the emissions factors are based on a limited
number of studies. The studies have been used to infer an "average" or
"typical" emissions factor, expressed in terms of grams per vehicle
distance traveled, or per unit of fuel consumed. Because of the large
number of emissions factor tables that represent all of the vehicles and
technology combinations, not all emissions factors are reproduced in
this document. A subset of factors does appear below in Table 1.D.2 in
subsection 1.D.3.2.1. Please refer to the EPA inventory for factors
specific to the United States. EIA, in its publication *Documentation
for Emissions of Greenhouse Gases in the United States 2003*, also
provides step-by-step emission estimation techniques, based on IPCC and
EPA emissions factors, for both mobile source nitrous oxide and methane
emissions.[^29] The IPCC also provides additional guidance, and factors
for other countries.[^30]^,^[^31] Other bodies, such as the EPA
voluntary programs,[^32] the WRI/WBCSD,[^33] and API,[^34] provide
additional guidance and reporters are encouraged to review those
guidance documents when preparing their inventories.

#### 1.D.3 Application and Ranking of Methods

##### 1.D.3.1 Carbon Dioxide from Mobile Combustion Systems

In mobile systems, carbon dioxide is generated by combustion systems
burning carbon- containing fuels such as motor gasoline, diesel fuel,
residual fuel oil, or jet fuel. All mobile sources that have combustion
systems generate carbon dioxide. Reporters that are estimating emissions
from mobile combustion systems that burn fossil fuels should include all
of the carbon dioxide in their emission inventories. Reporters that
operate vehicles using pure biofuels such as ethanol and biodiesel
within their entity should not add the carbon dioxide emissions from
those fuels to their inventory of mobile source emissions. If biofuel
blends (e.g., E85, a blend of 85 percent ethanol and 15 percent
gasoline, or B20, a blend of 20 percent biodiesel and 80 percent
petroleum-based diesel) are used, only the carbon dioxide associated
with the hydrocarbon portion should be reported, and the biogenic carbon
should not be added to the emissions inventory (refer to 1.D.4, "Special
Situations," below). If reporters operate electric vehicles, the
associated carbon dioxide emissions should be estimated using guidance
from Part F, "Indirect Emissions." Reporters operating hybrid
gas-electric vehicles need only report emissions from the combustion of
motor gasoline, because the electricity used is generated within the
vehicle and not obtained from the grid.

1.D.3.1.1 Highway Vehicles

This category includes a variety of on-road light- and heavy-duty
vehicles consuming a number of different fuels. Within this category,
on-road light- and heavy-duty vehicles using conventional fuels
(gasoline or diesel) include: passenger vehicles, hybrid-electric
vehicles, motorcycles, light-duty trucks (vans, pick-up trucks and sport
utility vehicles), medium-duty trucks, heavy-duty trucks, and buses.
Also included in this category are on-road vehicles using alternative
fuels (e.g., compressed natural gas, propane, methanol), which include
passenger vehicles, light-duty trucks, heavy-duty trucks, and buses.
Biofuel, electric, and fuel cell vehicles are not discussed in this
subsection (refer to 1.D.4, "Special Situations," below, for that
discussion).

As noted above, liquid fuel purchasers for highway vehicles will rarely
know more about the gasoline and diesel fuel they consume than the
volume purchased. In contrast to stationary combustion estimates,
therefore, the best available emissions estimate will use a default
emissions factor based upon the type and volume of fuel purchased,
although there are issues associated with how fuel consumption is
measured. The most accurate measurement of fuel consumption will usually
take place at the point of purchase. In most cases, fuel will be
purchased from a vendor and pumped directly into the tanks of the
vehicle, but reporters should be alert to the possibility of unreported
stock changes. This might occur, for example, when the reporter
purchases fuel in bulk, stores the fuel, and then refuels fuel to
vehicles as needed. In similar cases, reporters should modify actual
consumption by fluctuations in the quantity of fuel in storage.

For highway vehicles, carbon dioxide estimates using the mass balance
method are rated "A," provided that the volume of fuel burned is
measured by metered quantities of fuel loaded into the vehicle, or via
bulk purchase data that account for stock changes. Use of measured
density, heating value, or carbon content to estimate fuel
characteristics more accurately is preferred, if possible. If reporters
know the total heat content or volume of fuel consumed, they can use the
default emissions factors provided in Table 1.D.1. Reporters should
compare fuel consumption data with operating data (e.g., distance
traveled or operating hours) and document that the reported fuel
consumption data are reasonable.

###### Table 1.D.1. Carbon Dioxide Emissions Factors for Transportation Fuels

+---------------------------+---------------------+-------------------+
| **Transportation Fuel**   | **Carbon Dioxide    | **Carbon Dioxide  |
|                           | Emissions**         | Emissions**       |
|                           |                     |                   |
|                           | **(Pounds/Unit      | **(Metric Tons /  |
|                           | Volume)**           | Billion Btu)**    |
+---------------------------+---------------------+-------------------+
| Aviation Gasoline         | 18.15 per gallon    | 68.50             |
+---------------------------+---------------------+-------------------+
| Biodiesel/Biodiesel       | 0                   | 0                 |
| Blends^a^                 |                     |                   |
|                           | 17.71               | 59.17             |
| -   B100                  |                     |                   |
|                           | 19.93               | 65.86             |
| -   B20                   |                     |                   |
|                           | 21.04               | 69.16             |
| -   B10                   |                     |                   |
|                           | 21.70               | 71.12             |
| -   B5                    |                     |                   |
|                           |                     |                   |
| -   B2                    |                     |                   |
+---------------------------+---------------------+-------------------+
| Diesel Fuel (No.1 and     | 22.15 per gallon    | 72.43             |
| No.2)                     |                     |                   |
+---------------------------+---------------------+-------------------+
| Ethanol/Ethanol Blends^b^ | 0                   | 0                 |
|                           |                     |                   |
| -   E100                  | 2.9                 | 14.59             |
|                           |                     |                   |
| -   E85                   | 17.41               | 65.29             |
|                           |                     |                   |
| -   E10 (Gasohol)         |                     |                   |
+---------------------------+---------------------+-------------------+
| Motor Gasoline            | 19.36 per gallon    | 70.21             |
+---------------------------+---------------------+-------------------+
| Jet Fuel, Kerosene        | 20.88 per gallon    | 70.17             |
+---------------------------+---------------------+-------------------+
| Natural Gas               | 119.90 per 1000     | 52.80             |
|                           | cubic feet          |                   |
+---------------------------+---------------------+-------------------+
| Propane                   | 12.60 per gallon    | 62.76             |
+---------------------------+---------------------+-------------------+
| Residual Fuel (No.5 and   | 25.75 per gallon    | 78.02             |
| No.6 Fuel Oil)            |                     |                   |
+---------------------------+---------------------+-------------------+

Source: Energy Information Administration, *Documentation for Emissions
of Greenhouse Gases in the United States 2003,* (May 2005), p.189, web
site: www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

^a^ Emission factors for biodiesel blends were calculated using the net
(lower) heating value for biodiesel from National Biodiesel Board web
site:
[www.biodiesel.org/pdf_files/fuelfactsheets/BTU_Content_Final_Oct2005.pdf](http://www.biodiesel.org/pdf_files/fuelfactsheets/BTU_Content_Final_Oct2005.pdf).
The gross (higher) heating value was assumed to be 5% higher than the
net heating value (see Revised 1996 IPCC Guidelines for National
Greenhouse Gas Inventories: Reference Manual, p. 1.5, web site:
www.ipcc-nggip.iges.or.jp/public/gl/invs6.htm).

^b^ Emission factors for ethanol blends were calculated using the higher
heating value for ethanol from U.S. Department of Energy, Alternative
Transportation Fuel Data Center, web site:
www.eere.energy.gov/afdc/pdfs/fueltable.pdf.

Note: Fraction combusted is assumed to be 99 percent for liquid fuels
and 99.5 percent for gaseous fuels.

Carbon dioxide emissions estimates based on multiplying default
emissions factors by actual measured volumes from periodic bulk
purchases, but without accounting for stock changes, are rated "B."

Carbon dioxide estimates using the mass balance method are rated "C" if
the mass balance calculations are based on one of the following sets of
data, which must be available to the reporter:

-   Distance traveled activity data by vehicle type, and inferred or
    assumed vehicle fuel economy (both city and highway).

-   Vehicle-specific distance traveled activity data, and inferred or
    assumed vehicle fuel economy (both city and highway).

-   Hours, horsepower hours of operation, or ton-distance shipped and
    *specific* information on fuel consumed per unit of activity data
    from vehicle suppliers, manufacturers, or in-company records (e.g.,
    may be common for diesel-fueled trucks).

Carbon dioxide estimates using the mass balance method are rated "D" if
estimates are based on fuel price or expenditure data without
corresponding data on quantities purchased, if average annual or monthly
fuel prices are used to calculate fuel volume. Users of fuel expenditure
data for emissions estimation should be alert for fuel purchase records
being "contaminated" by purchases of unrelated non-fuel items from fuel
vendors.

Users of electric vehicles should refer to Part F, "Indirect Emissions,"
for methods of calculating emissions from the consumption of electricity
used to charge their vehicles.

###  {#section-4 .Normal-+-Times-New-Roman}

1.D.3.1.2 Off-Road Vehicles Including Diesel Locomotives

The off-road vehicle category includes a wide variety of vehicles
operating on conventional fuels such as gasoline, diesel, and fuel oil.
Vehicles within this category include construction equipment,
agricultural equipment, off-road recreational vehicles, snowmobiles, and
diesel locomotives. Most off-road vehicles will burn un-taxed (red-dyed)
diesel fuel (off-highway No. 2-D), which is generally very similar to
its taxed counterpart, while locomotives use a special railroad diesel.
Conventional snowmobiles and some other recreational off-road vehicles
have two-stroke spark-ignition engines that burn a gasoline-lubricant
mixture, though some relatively new snowmobiles may operate using
four-stroke spark-ignition engines that combust motor gasoline only.

Most railroad locomotives are powered by diesel engines, burning
railroad diesel fuel, though some corridors (notably in the Northeast)
are electrified, while subway and light rail (streetcar) systems are
usually electric. While operators of diesel-fueled railroad vehicles
should report emissions following the guidelines provided here for
off-road vehicles, operators of electrified rail systems should refer to
Part F, "Indirect Emissions," for methods of calculating emissions from
the consumption of electricity used to charge their vehicles.

For off-road vehicles, carbon dioxide estimates using the mass balance
method are rated "A," provided the mass balance estimates are based on
actual fuel quantities consumed as measured by metered quantities of
fuel loaded into the vehicle or by bulk purchase data that accounts for
stock changes. Use of measured density, heating value, or carbon content
to estimate fuel characteristics more accurately is preferred, if
possible. Reporters should compare fuel consumption data with operating
data (e.g., operating hours or distance traveled), and document that
reported fuel consumption data are reasonable.

Carbon dioxide estimates using the mass balance method based only on
bulk fuel purchase data not adjusted for stock changes, are rated "B."

Carbon dioxide estimates using the mass balance method are rated "C,"
provided the mass balance calculations are based on one of the following
sets of data, which must be available to the reporter:

-   Distance traveled data and fuel economy for each engine.

-   Hours, horsepower hours of operation, or ton-distance shipped and
    *specific* information on fuel consumed per unit of activity data
    from vehicle suppliers, manufacturers, or in-company records.

Carbon dioxide estimates using the mass balance method are rated "D" if
estimates are based on any of the following available data:

-   Fuel price data only.

-   Default factors for fuel consumption per unit of activity data.

1.D.3.1.3 Water Borne Vessels

Water borne vessels include recreational boats, patrol boats, cruise
ships, large freight vessels, container ships, and many other types of
vessels with various purposes. In general, very small boats (often less
than 50 feet in length) have spark ignition inboard, stern drive
(inboard/outboard or inboard/outdrive), or outboard engines that burn
gasoline. Some boats less than 50 feet in length may have inboard
compression ignition (i.e., diesel-cycle) engines that burn diesel fuel
or another distillate, residual fuel, or intermediate blend. Nearly all
commercial shipping vessels and cruise ships have large diesel engines
that burn residual fuel or an intermediate distillate-residual blend,
but it is possible that some of these compression ignition engines burn
a kerosene-based fuel. Some ships, especially high-speed ferries and
military vessels, have gas turbine engines that burn kerosene-based jet
fuel.

The propensity of merchant vessels to blend diesel and residual fuel
raises special problems for estimating emissions accurately, although
marine fuels are often sold by weight rather than by volume and the
carbon content of residual fuel is frequently known.

[]{.mark}

For water borne vessels, carbon dioxide estimates using the mass balance
method are rated "A," provided the mass balance estimates are based on
actual fuel quantities consumed, or via bulk fuel purchase data that
accounts for stock changes, and calculated using one of the following
sets of data, which must be available to the reporter:

-   Known weight and carbon content and default fraction combusted.

-   Weight or volume and actual heating value of fuel, and default
    carbon dioxide emission factor from Table 1.D.1.

-   Weight of fuel only and default carbon dioxide emission factor from
    Table 1.D.1.

-   Volume and actual density of fuel and default carbon dioxide
    emission factor from Table 1.D.1.

-   Specified fuel type and default carbon dioxide emissions factor
    (from Table 1.D.1, above).

Reporters should compare fuel consumption data with operating data
(e.g., operating hours or distance traveled) and document that reported
fuel consumption data are reasonable.

Carbon dioxide estimates using the mass balance method based only on
bulk fuel purchase data not adjusted for stock changes are rated "B."

Carbon dioxide estimates using the mass balance method are rated "C,"
provided the estimates of fuel quantity are derived from one of the
following sets of data, which must be available to the reporter:

-   Distance traveled data and fuel economy for each engine.

-   Hours, horsepower hours of operation, or ton-distance shipped and
    *specific* information on fuel consumed per unit of activity data
    from vehicle suppliers, manufacturers, or in-company records.

Carbon dioxide estimates using the mass balance method are rated "D" if
estimates of fuel quantity are derived from any of the following
available data:

-   Fuel price data only.

-   Default factors for fuel consumption per unit of activity data.

1.D.3.1.4 Aircraft

This category includes all aircraft running on kerosene jet fuel and
non-jet-engine planes that burn aviation gasoline, or less commonly,
motor gasoline. The vehicle types include turbine- and
piston-engine-driven aircraft, turbine-powered transport and air cargo
aircraft. Within this category, reporters will consider all civil
commercial uses of airplanes (international and domestic) consisting of
scheduled and chartered flights for passengers and freight. Emissions
from aircraft should be included in the entities inventory in the
country in which the fuel was purchased. This category also includes
civil commercial use of airplanes and helicopters for agricultural
purposes, instructional flying, business and pleasure flying, aerial
work, and any other flying.

As in other transportation instances, both aviation gasoline and jet
fuel are sold by volume, without reference to weight or carbon content.
Consequently, the most accurate available estimates of emissions will
generally be based on the use of default emissions factors and estimates
of fuel volume.

For aircraft, carbon dioxide estimates using the mass balance method are
rated "A," provided that the volume of fuel burned is measured by
metered quantities of fuel loaded into the vehicle, or via bulk purchase
data that account for stock changes. Use of measured density, heating
value, or carbon content to estimate fuel characteristics is preferred,
if possible. Reporters should compare fuel consumption data with
operating data (e.g., flight hours or operating hours) to document that
reported fuel consumption data are reasonable.

Carbon dioxide estimates using the mass balance method based only on
fuel consumption volume are rated "B" if the data reflect bulk fuel
quantities that do not account for stock changes. Aviation entities may
keep large fuel stocks on site, which could significantly influence
annual emissions estimates when not reporting changes in stock.

Carbon dioxide estimates using the mass balance method are rated "C,"
provided the estimates of fuel quantity are derived from one of the
following sets of data, which must be available to the reporter:

-   Distance traveled data and fuel economy for each engine.

-   Hours, horsepower hours of operation, or ton-distance shipped and
    *specific* information on fuel consumed per unit of activity data
    from vehicle suppliers, manufacturers, or in-company records.

Carbon dioxide estimates using the mass balance method are rated "D" if
estimates of fuel quantity are derived from any of the following
available data:

-   Fuel price data only.

-   Default factors for fuel consumption per unit of activity data.

##### 1.D.3.2 Methane and Nitrous Oxide from Mobile Combustion Systems

**1.D.3.2.1 Highway Vehicles**

For highway vehicles, estimates of methane and nitrous oxide emissions
using the inference method based on vehicle distance traveled or fuel
consumption and an emissions factor for specific vehicle types are rated
"A," provided the combustion and emission control technology type are
known for each vehicle.

Methane and nitrous oxide emission estimates using the inference method
based on total vehicle distance traveled (for an uncharacterized vehicle
mix) and an emissions factor that represents the weighted average of
available control technologies by model year is rated "B." Those
weighted averages are provided by the EPA Climate Leaders voluntary
program.[^35]

The methane and nitrous oxide emissions factors for U.S. highway
vehicles developed by the EPA cover a number of vehicle types with
various control technologies. The vehicle types include gasoline
passenger cars, light-duty trucks, and heavy-duty vehicles; diesel
passenger cars, light-duty trucks, and heavy-duty vehicles; and
motorcycles. The control technology categories for gasoline vehicles
include low emission vehicle technology, three-way catalyst controls
(EPA Tier 1), early three-way catalysts (EPA Tier 0), oxidation
catalysts, non-catalyst controls, and uncontrolled. The control
technology categories for diesel vehicles are advanced, moderate, and
uncontrolled, and the control technology categories for motorcycles are
non-catalyst control and uncontrolled. EPA provides control technology
assignments for vehicle types based on model year.[^36] For example, all
gasoline-fueled passenger cars of model years 1984-1993 have the control
technology EPA Tier 0/Early Three-Way Catalyst.

The IPCC provides a range of methane emissions factors for all highway
vehicles and control technologies broken down into Spring/Fall, Summer,
and Winter seasons. These factors also are averaged and expressed in
terms of grams per kilometer, grams per kilogram fuel and grams per mega
joule. Averaged single emissions factors are provided for nitrous oxide
expressed in terms of grams per kilometer, grams per kilogram fuel and
grams per mega joule.[^37] In addition, EPA developed methane and
nitrous oxide emissions factors using a weighted average of control
technologies by vehicle model year for cases where data on specific
control technologies are unavailable.[^38] Expressed in terms of grams
per mile, these emissions factors cover gasoline passenger cars, vans,
pickup trucks, sport utility vehicles and heavy-duty vehicles for model
years 1984-2003. For diesel passenger cars, light trucks, and heavy-duty
vehicles, the emissions factors cover model years 1966-2001.[^39] Table
1.D.2, below, presents suggested emissions factors for methane and
nitrous oxide for highway vehicles, which can be used with control
technology assignment data referenced above and defined in Table 1.D.3.
If the specific control technology for the vehicle(s) is not known,
reporters can use the emission coefficients for the predominant control
technology for the model year of the vehicle(s) shown in Table 1D.4.

For alternative fuel vehicles, the EPA developed methane and nitrous
oxide emissions factors covering light-duty vehicles, heavy-duty
vehicles, and buses. For light-duty vehicles, emissions factors are
provided for methanol, compressed natural gas, liquefied petroleum gas
(propane) and ethanol fuel types. For heavy-duty vehicles, emissions
factors are available for liquefied natural gas in addition to the fuel
types listed for light-duty vehicles. For buses, emissions factors are
available for methanol and compressed natural gas. The emissions factors
are expressed in terms of grams per mile and grams per kilometer.[^40]

###### Table 1.D.2: Emissions Factors for Methane and Nitrous Oxide for Highway Vehicles

  ------------------------------- ---------- ---------- ---------- ----------
  **Vehicle Type/Control          **N~2~O    **CH~4~    **N~2~O    **CH~4~
  Technology**                    (g/mi)**   (g/mi)**   (g/km)**   (g/km)**

  **Gasoline Passenger Cars**                                      

  Low Emission Vehicles           0.0222     0.0169     0.0138     0.0105

  EPA Tier 1                      0.0429     0.0271     0.0267     0.0168

  EPA Tier 0                      0.0647     0.0704     0.0402     0.0437

  Oxidation Catalyst              0.0504     0.1355     0.0313     0.0842

  Non-Catalyst                    0.0197     0.1696     0.0122     0.1054

  Uncontrolled                    0.0197     0.1780     0.0122     0.1106

  **Gasoline Light-Duty Trucks**                                   

  Low Emission Vehicles           0.0146     0.0216     0.0091     0.134

  EPA Tier 1                      0.0871     0.0452     0.0541     0.0281

  EPA Tier 0                      0.1056     0.0776     0.0656     0.0482

  Oxidation Catalyst              0.0639     0.1516     0.0397     0.0942

  Non-Catalyst                    0.0218     0.1908     0.0135     0.1186

  Uncontrolled                    0.0220     0.2024     0.0137     0.1258

  **Gasoline Heavy-Duty                                            
  Vehicles**                                                       

  Low Emission Vehicles           0.0290     0.0434     0.0180     0.0270

  EPA Tier 1                      0.1750     0.0655     0.1087     0.0407

  EPA Tier 0                      0.2135     0.2630     0.1326     0.1634

  Oxidation Catalyst              0.1317     0.2536     0.0818     0.1464

  Non-Catalyst Control            0.0473     0.4181     0.0294     0.2598

  Uncontrolled                    0.0497     0.4604     0.0309     0.2861

  **Diesel Passenger Cars**                                        

  Advanced                        0.0010     0.0005     0.0006     0.0003

  Moderate                        0.0010     0.0005     0.0006     0.0003

  Uncontrolled                    0.0012     0.0006     0.0008     0.0004

  **Diesel Light-Duty Trucks**                                     

  Advanced                        0.0015     0.0005     0.0009     0.0003

  Moderate                        0.0014     0.0005     0.0009     0.0003

  Uncontrolled                    0.0017     0.0006     0.0010     0.0004

  **Diesel Heavy-Duty Vehicles**                                   

  Advanced                        0.048      0.0051     0.030      0.0032

  Moderate                        0.048      0.0051     0.030      0.0032

  Uncontrolled                    0.048      0.0051     0.030      0.0032

  **Motorcycles**                                                  

  Non-Catalyst Control            0.0069     0.0672     0.0043     0.418

  Uncontrolled                    0.0087     0.0899     0.0054     0.559
  ------------------------------- ---------- ---------- ---------- ----------

Source: U.S. Environmental Protection Agency. *Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2003*, Annex 3.2, (April 2005),
web site:
yosemite.epa.gov/OAR/globalwarming.nsf/content/ResourceCenterPublicationsGHGEmissionsUSEmissionsInventory2005.html.

Note: Reporters should refer to the most recent EPA publication of the
*Inventory of U.S. Greenhouse Gas Emissions and Sinks* for Tier 2
vehicle emission factors, when they become available. The Tier 2 Program
sets new standards for tailpipe emissions for all passenger vehicles
beginning in 2004. The Tier 2 Program also requires reduced levels of
sulfur in gasoline.

###### Table 1.D.3 Definitions of Emission Control Technologies and Standards

+-----------------------------------------------------------------------+
| **Uncontrolled**                                                      |
+-----------------------------------------------------------------------+
| -   Vehicles manufactured prior to the implementation of pollution    |
|     control technologies are designated as uncontrolled. Gasoline     |
|     light-duty cars and trucks (pre-1973), gasoline heavy-duty        |
|     vehicles (pre-1984), diesel vehicles (pre-1983), and motorcycles  |
|     (pre-1996) are assumed to have no control technologies in place.  |
+-----------------------------------------------------------------------+
| **Gasoline Emission Controls**                                        |
+-----------------------------------------------------------------------+
| -   Non-catalyst -- These emission controls were common in gasoline   |
|     passenger cars and light-duty gasoline trucks during model years  |
|     (1973-1974) but phased out thereafter, in heavy-duty gasoline     |
|     vehicles beginning in the mid-1980s, and in motorcycles beginning |
|     in 1996. This technology reduces hydrocarbon (HC) and carbon      |
|     monoxide (CO) emissions through adjustments to ignition timing    |
|     and air-fuel ratio, air injection into the exhaust manifold, and  |
|     exhaust gas recirculation (EGR) valves, which also helps meet     |
|     vehicle NOx standards.                                            |
+-----------------------------------------------------------------------+
| -   Oxidation Catalyst -- This control technology designation         |
|     represents the introduction of the catalytic converter, and was   |
|     the most common technology in gasoline passenger cars and         |
|     light-duty gasoline trucks made from 1975 to 1980 (cars) and 1975 |
|     to 1985 (trucks). This technology was also used in some           |
|     heavy-duty gasoline vehicles between 1982 and 1997. The two-way   |
|     catalytic converter oxidizes HC and CO, significantly reducing    |
|     emissions over 80 percent beyond non-catalyst-system capacity.    |
|     One reason unleaded gasoline was introduced in 1975 was due to    |
|     the fact that oxidation catalysts cannot function properly with   |
|     leaded gasoline.                                                  |
+-----------------------------------------------------------------------+
| -   EPA Tier 0 -- This emission standard from the Clean Air Act was   |
|     met through the implementation of early \"three-way\" catalysts,  |
|     therefore this technology was used in gasoline passenger cars and |
|     light-duty gasoline trucks sold beginning in the early 1980s, and |
|     remained common until 1994. This more sophisticated emission      |
|     control system improves the efficiency of the catalyst by         |
|     converting CO and HC to CO~2~ and H~2~O, reducing NO~X~ to        |
|     nitrogen and oxygen, and using an on-board diagnostic computer    |
|     and oxygen sensor. In addition, this type of catalyst includes a  |
|     fuel metering system (carburetor or fuel injection) with          |
|     electronic \"trim\" (also known as a \"closed-loop system\"). New |
|     cars with three-way catalysts met the Clean Air Act\'s amended    |
|     standards (enacted in 1977) of reducing HC to 0.41 g/mile by      |
|     1980, CO to 3.4 g/mile by 1981 and NO~x~ to 1.0 g/mile by 1981.   |
+-----------------------------------------------------------------------+
| -   EPA Tier 1 -- This emission standard created through the 1990     |
|     amendments to the Clean Air Act limited passenger car NOx         |
|     emissions to 0.4 g/mi, and HC emissions to 0.25 g/mi. These       |
|     bounds respectively amounted to a 60 and 40 percent reduction     |
|     from the EPA Tier 0 standard set in 1981. For light-duty trucks,  |
|     this standard set emissions at 0.4 to 1.1 g/mi for NO~x~, and     |
|     0.25 to 0.39 g/mi for HCs, depending on the weight of the truck.  |
|     Emission reductions were met through the use of more advanced     |
|     emission control systems, and applied to light-duty gasoline      |
|     vehicles beginning in 1994. These advanced emission control       |
|     systems included advanced three-way catalysts, electronically     |
|     controlled fuel injection and ignition timing, EGR, and air       |
|     injection.                                                        |
+-----------------------------------------------------------------------+
| -   Low Emission Vehicles (LEV) -- This emission standard requires a  |
|     much higher emission control level than the Tier 1 standard.      |
|     Applied to light-duty gasoline passenger cars and trucks          |
|     beginning in small numbers in the mid-1990s, LEV includes         |
|     multi-port fuel injection with adaptive learning, an advanced     |
|     computer diagnostics systems and advanced and close coupled       |
|     catalysts with secondary air injection. LEVs as defined here      |
|     include transitional low-emission vehicles (TLEVs), low emission  |
|     vehicles, ultra-low emission vehicles (ULEVs) and super ultra-low |
|     emission vehicles (SULEVs). In this analysis, all categories of   |
|     LEVs are treated the same due to the fact that there are very     |
|     limited CH4 or N2O emission factor data for LEVs to distinguish   |
|     among the different types of vehicles. Zero emission vehicles     |
|     (ZEVs) are incorporated into the alternative fuel and advanced    |
|     technology vehicle assessments.                                   |
+-----------------------------------------------------------------------+
| **Diesel Emission Controls**                                          |
+-----------------------------------------------------------------------+
| -   Moderate control -- Improved injection timing technology and      |
|     combustion system design for light- and heavy-duty diesel         |
|     vehicles (generally in place in model years 1983 to 1995) are     |
|     considered moderate control technologies. These controls were     |
|     implemented to meet emission standards for diesel trucks and      |
|     buses adopted by the EPA in 1985 to be met in 1991 and 1994.      |
+-----------------------------------------------------------------------+
| -   Advanced control -- EGR and modern electronic control of the fuel |
|     injection system are designated as advanced control technologies. |
|     These technologies provide diesel vehicles with the level of      |
|     emission control necessary to comply with standards in place from |
|     1996 through 2004.                                                |
+-----------------------------------------------------------------------+

Source: U.S. Environmental Protection Agency. *Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2004*, Annex 3.2 (February
2006), p. A-132-A-133, web site:
http://yosemite.epa.gov/oar/globalwarming.nsf/UniqueKeyLookup/RAMR6MBLNQ/\$File/06_annex_Chapter%203.pdf.

###### Table 1.D.4: Predominant Control Technology by Model Year 

  --------------------- ----------------------- -------------------------
  **Vehicle Type**      **Model Year**          **Predominant Control
                                                Technology**

  Gasoline Passenger    2000 and Later          Low Emission Vehicle
  Cars                                          

                        1995-1999               EPA Tier 1

                        1981-1994               EPA Tier 0

                        1975-1980               Oxidation Catalyst

                        1973-1974               Non-catalyst

                        1972 and Earlier        Uncontrolled

  Gasoline Light-Duty   2001 and Later          Low Emission Vehicle
  Trucks                                        

                        1995-2000               EPA Tier 1

                        1986-1994               EPA Tier 0

                        1975-1985               Oxidation Catalyst

                        1973-1974               Non-catalyst

                        1972 and Earlier        Uncontrolled

  Gasoline Heavy-Duty   1996 and Later          EPA Tier 1
  Vehicles                                      

                        1985-1995               Non-catalyst

                        1984 and Earlier        Uncontrolled

  Diesel Vehicles       1996 and Later          Advanced
  (Passenger Cars and                           
  Light- and Heavy-Duty                         
  Trucks)                                       

                        1983-1995               Moderate

                        1982 and Earlier        Uncontrolled

  Motorcycles           1996 and Later          Non-Catalyst Control

                        1995 and Earlier        Uncontrolled
  --------------------- ----------------------- -------------------------

Source: U.S. Environmental Protection Agency, Inventory of U.S.
Greenhouse Gases Emissions and Sinks: 1990-2003, EPA 430-R-05-003, April
15, 2005, Annex 3, Methodological Descriptions for Additional Source or
Sink Categories, Tables 3-24, 3-25, 3-26, and 3-27.

1.D.3.2.2 Off-Road Vehicles and Marine Vessels

For off-road vehicles, the IPCC developed methane and nitrous oxide
emissions factors covering ocean-going ships, boats, locomotives,
agricultural equipment, and construction equipment. The emissions
factors are expressed in terms of grams per kilogram fuel and grams per
megajoule.[^41] Some off-road vehicle operators may keep records of fuel
consumption or vehicle miles traveled, although for many off-road
vehicle types (such as construction equipment), activity data may only
be available in terms of hours of use.

For off-road vehicles and marine vessels, methane and nitrous oxide
estimates using the inference method, when fuel or energy consumption
data are known, are rated "A," provided IPCC non-road mobile
source-specific emissions factors are used.[^42]

Methane and nitrous oxide estimates using the inference method, when
fuel or energy consumption data are not known but are calculated based
on other activity data (e.g., distance traveled, hours, or
horsepower-hours of operation) are rated "B," provided fuel economy
factors are vehicle model-specific factors, or are based on the engine
manufacturer specifications or other operation-specific data source. For
freight transport, reporters must take into account time spent idling if
estimating fuel consumption based on other activity data.

Methane and nitrous oxide estimates using the inference method, when
fuel or energy consumption data are not known but are calculated based
on default/generic fuel economy values derived from the Oak Ridge
National Lab's [Transportation Energy Book]{.underline}[^43] (e.g.,
based on different or unspecific engine model) other activity data
(e.g., distance traveled, hours, or horsepower-hours of operation) are
rated "C."

**1.D.3.2.3 Aircraft**

The IPCC provides a "Tier II" method for calculating nitrous oxide and
methane emissions from aviation, based on distinguishing between Landing
and Take-off Operations (LTO) and cruise operations (flight at
altitude). Close examination of the IPCC emissions factors suggests that
for greenhouse gases, however, the two methods are based upon a single
default emissions factor per kilogram of fuel burned.[^44] For aircraft,
the IPCC developed methane and nitrous oxide emissions factors covering
jet and turboprop aircraft and gasoline (piston) aircraft. The emissions
factors are expressed in terms of grams per kilogram fuel and grams per
(lower heating value) megajoule.[^45]

For aircraft, methane and nitrous oxide estimates using the inference
method based on individual jet engine aircraft LTO and cruise data and
IPCC default emissions factors[^46] are rated "A."

Methane and nitrous oxide estimates using the inference method, when
fuel or energy consumption data are known, using either the LTO approach
or emissions per kilogram of fuel, are rated "B," provided IPCC
aircraft-specific emissions factors[^47] are used.

Methane and nitrous oxide estimates using the inference method, when
fuel or energy consumption data are not known but are calculated based
on other activity data (e.g., distance traveled, hours, or
horsepower-hours of operation), are rated "C," provided fuel economy
factors are vehicle model-specific factors, or are based on the engine
manufacturer specifications or other operation-specific data source. For
freight transport, reporters must take into account time spent idling if
estimating fuel consumption based on other activity data.

Methane and nitrous oxide estimates using the inference method, when
fuel or energy consumption data are not known but are calculated based
on other activity data (e.g., distance traveled, hours, or
horsepower-hours of operation) and default/generic fuel economy values
from any other source or estimations are rated "D."

##### 1.D.3.3 Hydrofluorocarbons from Mobile Refrigeration and Air Conditioning

This section includes all transportation vehicles that have mobile
refrigeration and air conditioning systems, including those vehicles
that do not produce anthropogenic carbon dioxide emissions or direct
methane and nitrous oxide emissions, but can emit hydrofluorocarbons
from refrigeration and/or air conditioning systems.

Hydrofluorocarbon estimates using the mass balance method are rated "A,"
provided the mass balance estimates have the following features and data
availability:

-   Amount of refrigerant inventory per year charged into new and
    retrofitted equipment.

-   Amount of refrigerant inventory per year used to service equipment
    and replace leaked and vented refrigerant.

-   Total full capacity of each system, including original full capacity
    of retiring equipment.

-   Quantities of refrigerants recovered per year from all vehicles and
    mobile systems.

Hydrofluorocarbon estimates using the mass balance method are rated "C"
if the estimates are based on emissions factors (percent) for initial
charge, annual leakage during operation, capacity remaining at disposal,
and recovery. This mass balance approach using emissions factors is
based on the Tier 2 approach from the IPCC Good Practice Guidance and
the EPA Climate Leaders voluntary program method. These authorities
provide default values for mobile air conditioning equipment input
parameters, including emissions factors.[^48]

All methods and ratings discussed in this chapter for estimating
greenhouse gas emissions from mobile sources are summarized below in
Table 1.D.5.

###### Table 1.D.5. Summary of Methods and Ratings for Estimates of Greenhouse Gas Emissions from Mobile Sources

  ---------------------------------------------------------------------------
  **Method Description**                                         **Rating**
  -------------------------------------------------------------- ------------
  **Carbon Dioxide Emissions from Highway Vehicles**             

  Mass balance based on fuel volume burned, or bulk purchase     A
  data adjusted for stock change used with measured density or   
  heating value and carbon content or with default emissions     
  factors                                                        

  Mass balance based on bulk fuel purchase not accounting for    B
  stock change used with default emissions factors               

  Mass balance based on distance traveled and fuel economy data, C
  or hours, horsepower-hours, or ton-distance shipped and fuel   
  consumption per unit activity data used with default emissions 
  factors                                                        

  Mass balance based on fuel price or expenditure data used with D
  default emissions factors                                      

  **Carbon Dioxide Emissions from Off-Road Vehicles, Including   
  Diesel Locomotives**                                           

  Mass balance based on actual fuel consumed or via bulk         A
  purchase data that accounts for stock change used with         
  measured density or heating value and carbon content or with   
  default emissions factors                                      

  Mass balance using fuel consumption based on bulk purchase not B
  accounting for stock change used with default emissions        
  factors                                                        

  Mass balance based on distance traveled and fuel economy for   C
  each engine, or hours, horsepower hours of operation, or       
  ton-distance shipped and fuel consumed per unit activity data  
  used with default emissions factors                            

  Mass balance based on fuel price data only or default factors  D
  for fuel consumption per unit activity data used with default  
  emissions factors                                              

  **Carbon Dioxide Emissions from Water Borne Vessels**          

  Mass balance based on actual fuel quantities consumed or bulk  A
  purchase records accounting for stock change used with         
  measured density, heating value, and/or carbon content and/or  
  with specific fuel type and default emissions factors          

  Mass balance based on bulk fuel purchase data not adjusted for B
  stock change used with default emissions factors               

  Mass balance based on distance traveled data and fuel economy  C
  for each engine, or hours, horsepower hours of operation, or   
  ton-distance shipped and specific information on fuel consumed 
  per unit activity data used with default emissions factors     

  Mass balance based on fuel price data only or default factors  D
  for fuel consumption per unit of activity data used with       
  default emissions factors                                      

  **Carbon Dioxide Emissions from Aircraft**                     

  Mass balance based on measured quantities loaded into vehicle  A
  or bulk purchase records accounting for stock change used with 
  measured density or heating value, and carbon content or with  
  default emissions factors                                      

  Mass balance fuel consumption volume from bulk purchase data   B
  not adjusted for stock change used with default emissions      
  factors                                                        

  Mass balance based on distance traveled and fuel economy for   C
  each engine, or hours, horsepower hours, or ton-distance       
  shipped and specific information on fuel consumed per unit     
  activity data used with default emissions factors              

  Mass balance based on fuel price data only or default factors  D
  for fuel consumption per unit of activity data used with       
  default emissions factors                                      

  **Methane and Nitrous Oxide from Highway Vehicles**            

  Inference based on vehicle distance traveled or fuel           A
  consumption and an emissions factor for specific vehicle       
  types, provided combustion and emission control technology are 
  known for each vehicle                                         

  Inference based on total vehicle distance traveled for an      B
  uncharacterized vehicle mix and weighted average emissions     
  factor                                                         

  **Methane and Nitrous Oxide from Off-Road Vehicles and Marine  
  Vessels**                                                      

  Inference based on fuel or energy consumption data and         A
  specific IPCC emissions factors                                

  Inference based other activity data (e.g., distance traveled)  B
  to calculate fuel consumption, with model-specific fuel        
  economy factors and IPCC emissions factors                     

  Inference based on default/generic fuel economy values and     C
  available activity data with IPCC emissions factors            

  **Methane and Nitrous Oxide from Aircraft**                    

  Inference based on individual jet engine aircraft LTO and      A
  cruise data and IPCC default emissions factors                 

  Known fuel/energy consumption and either LTO approach or       B
  emissions per kilogram fuel with IPCC default emissions        
  factors                                                        

  Inference based on other activity data (e.g., distance         C
  traveled) use to calculate fuel consumption used with default  
  IPCC emission factors, provided fuel economy data are          
  model-specific                                                 

  Inference using other activity data (e.g., hours) and          D
  default/generic fuel economy values with IPCC default          
  emissions factors                                              

  **Hydrofluorocarbons from Mobile Refrigeration and Air         
  Conditioning**                                                 

  Mass balance, provided specific features and data availability A

  Mass balance based on emissions factors (percent) for initial  C
  charge, annual leakage, capacity remaining at disposal, and    
  recovery                                                       
  ---------------------------------------------------------------------------

#### 1.D.4 Special Situations

[]{.mark}

##### 1.D.4.1 Electric, Fuel Cell, and Bio-Fueled Vehicles

Whenever mobile emissions sources combust liquid or gaseous fuel, they
emit carbon dioxide, methane, and nitrous oxide. The relative amounts of
those emissions will depend on many factors, but the actual gases
emitted are the same. The exceptions to this rule are electric vehicles,
fuel cell vehicles, and bio-fueled vehicles because they do not combust
fuels or the fuels they do combust are biogenic.

Electric vehicles have no tailpipe emissions, although there may be
significant upstream emissions depending on the source of the
electricity. If produced from renewable energy there will be no upstream
emissions, but if generated from fossil fuels there will be a
significant upstream share of emissions in the form of carbon dioxide,
methane, and nitrous oxide. Upstream emissions from electricity that is
subsequently used in electric vehicles should be estimated by the entity
operating the vehicles as described in Part F, "Indirect Emissions."

Hydrogen-powered fuel cell vehicles also have no tailpipe emissions of
reportable greenhouse gases, although there may be significant upstream
emissions depending on the source of the hydrogen. If the hydrogen is
produced from renewable energy or nuclear energy, there will be no
upstream emissions. If it is reformed from natural gas or other fossil
fuels -- and sequestration does not occur -- there will be a significant
upstream share of greenhouse gas emissions in the form of carbon
dioxide, methane, and nitrous oxide. If the hydrogen is generated from
natural gas, any upstream emissions may be reported using guidelines for
industrial process direct emissions by the entity processing the natural
gas. If the hydrogen used in the fuel cell is generated from water by
electrolysis, the entity producing the hydrogen may report any indirect
emissions from electricity that was used to charge a battery used in the
electrolytic process, if applicable.

Reporters that operate vehicles using pure biofuels within their entity
should not add the carbon dioxide emissions from those fuels to their
inventory of mobile source emissions because such emissions are
considered biogenic and the recycling of the carbon is not credited
elsewhere. If vehicles are operating on a gasoline/alcohol blend such as
E85, or "gasohol," reporters should calculate emissions for the
hydrocarbon fraction of the fuel that is combusted and include those
emissions with the inventory of carbon dioxide from mobile sources. For
example, E85 is composed of 85 percent ethanol and 15 percent gasoline
by volume, and the carbon dioxide emissions from the gasoline portion of
the fuel should be calculated according to the methods described above.

**Technical Guidelines for Voluntary Reporting of Greenhouse Gases
Program**

**Chapter 1, Emission Inventories**

### Part E: Industrial Processes

Outline

1.  Overview

2\. Emission Sources

> 2.1. Process Emissions
>
> 2.2. Fugitive Emissions
>
> 2.3. Process Emissions vs. Combustion Emissions

3\. Estimation Methods

> 3.1. Direct Measurement
>
> 3.2. Mass (or Material) Balance
>
> 3.3. Inference

4\. Sector-Specific Emission Estimation Guidance

> 4.1. Industrial Processes
>
> 4.1.1. Adipic Acid Production
>
> 4.1.2. Aluminum Production
>
> 4.1.3. Ammonia Production
>
> 4.1.4. Cement Production
>
> 4.1.5. Hydrogen Production
>
> 4.1.6. Iron and Steel Production
>
> 4.1.7. Lime Production
>
> 4.1.8. Limestone and Dolomite Use
>
> 4.1.9. Methanol Production
>
> 4.1.10. Methane Emissions from Production of Other Petrochemicals
>
> 4.1.11. Nitric Acid Production
>
> 4.1.12. Soda Ash Production and Use
>
> 4.2. Energy
>
> 4.2.1. Coal Mining
>
> 4.2.2. Oil and Natural Gas Industries
>
> 4.3. Waste Handling
>
> 4.3.1. Methane Emissions from Domestic and Industrial Wastewater
> Handling
>
> 4.3.2. Nitrous Oxide Emissions from Domestic Wastewater
>
> 4.3.3. Landfill Methane
>
> 4.4. High Global Warming Potential Gases
>
> 4.4.1. Aluminum Production
>
> 4.4.2. HCFC-22 Production
>
> 4.4.3. SF~6~ Emissions from Electrical Equipment
>
> 4.4.4. Industrial Use and Production of Hydrocarbons, Perfluorocarbons
> and Sulfur Hexafluoride
>
> 4.4.5. Magnesium Production
>
> 4.4.6. Semiconductor Manufacture
>
> 4.5. Special Situations: Geologic Sequestration

**Technical Guidelines Chapter 1, Part E: Industrial Processes**

#### 1.E.1 Overview

This Part of the Technical Guidelines presents methods for estimating
emissions of greenhouse gases from industrial processes, energy
industries, and waste handling. These sectors encompass many processes,
activities, and products. Emission sources in these sectors are also
varied, and include the byproducts of chemical transformations, the use
and discharge of gases, and periodic, non-production-related practices
such as maintenance and system upgrades. Discussion of energy industries
includes the coal, natural gas and oil industries, while the waste
sector focuses on emissions from landfills and wastewater.

This Part does not attempt to provide a comprehensive list of sources or
detailed guidance for estimating emissions from all processes. It does,
however, describe and rank methods for estimating emissions from the
following industries and industrial activities: adipic acid production;
aluminum production; ammonia production; cement production; coal mining;
HCFC-22 production; industrial use of hydrofluorocarbons (HFCs),
perfluorocarbons (PFCs), and sulfur hexafluoride (SF~6~); iron and steel
production; landfill methane; lime production; limestone and dolomite
use; magnesium production; methanol production; nitric acid production;
the oil and natural gas industries; semiconductor manufacturing; soda
ash production and use; and domestic and industrial wastewater handling.

Estimation methods for industrial sources include direct monitoring
(including continuous and periodic emission monitoring), mass balance,
and inference based on derived emissions factors. This section defines
these methods and provides guidance for implementing emission estimates
for various industrial processes, but reporters are encouraged to
consult published authorities for more complete instruction,[^49]
particularly for industries in which emissions originate from a variety
of sources or require complex estimation methods.

Reporters cataloging industrial emissions should ensure that the same
emissions are not "double counted," or recorded simultaneously under
different sections. In particular, where the primary purpose of an
industrial process is energy production (in the form of heat or
electricity), emissions should be attributed to stationary combustion
(see Part C, "Stationary Combustion").

#### 1.E.2 Emission Sources

##### 1.E.2.1 Process Emissions

Emissions are generated and released during the chemical transformation
of materials at some stage of the production process in many industries.
These emissions are referred to as "process emissions" and are usually
the byproduct of a known chemical reaction. Greenhouse gas emissions
from processes of this type include carbon dioxide (CO~2~), methane
(CH~4~), nitrous oxide (N~2~O), trifluoromethane (HFC-23), and
perfluorocarbons (PFCs). Industries and industrial activities that
generate emissions through chemical processes include adipic acid
production, chlorodifluoromethane (HCFC-22) production, aluminum
production, cement manufacturing, iron and steel production, lime
manufacture, limestone and dolomite use, nitric acid production, and
soda ash manufacture and use. Process emissions from industrial chemical
reactions represent 4 to 5 percent of total U.S. greenhouse gas
emissions on a carbon dioxide equivalent basis.[^50]

##### 1.E.2.2 Fugitive Emissions

"Fugitive emissions" is a broad term that includes both unintentional
and sometimes intended emissions from non-distinct or non-confined
sources. Fugitive emissions occur during the production and distribution
of a chemical, compound, or mixture of compounds and are usually the
result of leaks in transportation or processing systems. Fugitive
emissions can be significant in terms of both carbon dioxide equivalents
and percentages of equipment charge.

Reporters may expect fugitive emissions in industries where greenhouse
gases are transported or used in a specific process or application.
Relevant industrial processes include magnesium production, production
and use of refrigerants, oil and natural gas extraction, processing and
transportation, and the production and use of hydrofluorocarbons,
perfluorocarbons and sulfur hexafluoride. Fugitive emissions may also
occur during the extraction, transport and preparation of coal or from
anaerobic decomposition of wastes in landfills. Fugitive emissions
account for nearly 6 percent of all U.S. greenhouse gas emissions.[^51]
The natural gas industry is the industry most likely to report fugitive
emissions on a significant scale.

Fugitive emissions may also result from "non-routine" activities in
industries that transport or process large volumes of greenhouse gases.
Non-routine activities are those that are not part of typical processing
activities, but occur periodically as a part of overall system
operations. These activities can be either planned or unplanned, and
include maintenance and turnaround activities, line and equipment
purging, and unplanned system depressurization in response to emergency
conditions.

##### 1.E.2.3 Process Emissions vs. Combustion Emissions

Many industrial processes are dependent on a significant amount of
energy, such as process heat, electricity use, or some other form of
energy consumption. A key distinction of industrial emissions, however,
is that they result from a non-energy-related activity. For processes in
which the use or consumption of one material serves more than one
purpose, it is important for reporters to accurately allocate emissions
and to avoid double counting.

The iron industry provides an example of this situation, where coke is
used in blast furnaces to provide process heat as well as to reduce the
iron in raw ore. In these cases, reporters should consider whether the
role of the process in question is to provide usable energy or is an
intrinsic element of the industrial process. As in the case of the iron
industry, where the reduction of iron is a critical component in
producing crude iron, emissions should be counted as industrial. Where
the primary purpose of a process is to use the heat that is released,
emissions should be attributable to stationary combustion.

#### 1.E.3 Estimation Methods

##### 1.E.3.1 Direct Measurement

Reporters may directly monitor their industrial process stack emissions
even when not required to do so by the Clean Air Act Amendments. They
may be complying with other environmental regulations, or collecting
process performance information for internal purposes. In cases where
emissions are channeled through dedicated streams, direct measurements
may help reporters differentiate between stationary combustion and
industrial process emissions. Direct emission measurements can be taken
either continuously or periodically.

Continuous emission monitoring (CEM) is one method of direct
measurement. CEM requires inserting a probe into the exhaust stack of an
industrial process system, and continuously measuring and recording
concentrations of gases that flow through the exhaust pipe. Due to its
relatively high cost and a general absence of regulatory requirements,
however, CEM is fairly uncommon for measuring greenhouse gas emissions
from industrial processes. Nevertheless, continuous or frequent
measurements are critical for some industrial entities to ensure process
efficiency (e.g., HCFC-22 production), and are therefore performed
without regulation. Those measurements are often made rigorously because
they have a high economic impact.

Emissions can also be estimated through periodic direct measurements.
Like CEM, periodic measurements directly measure emissions passing
through exhaust streams. As the name implies, though, periodic
measurements only provide samples of the exhaust stream at particular
points in time. The data gathered from these measurements are used in
conjunction with estimates of exhaust flow rates and other activity data
to extrapolate to total emissions over a given period of time. Since
periodic measurements yield a sample of total emissions, any difference
in the quality of data with the CEM approach will depend upon the
information available about the emissions profile. If exhaust flow rates
are well known, as might be the case for a plant that operates at the
same level continuously, there may be very little difference in
emissions estimates from the two methods. For a plant whose output
varies over time, producing a data set from periodic measures whose
accuracy compares with that from CEM measurements can be challenging.

Reporters should use unregulated emissions monitoring data with caution;
measured emissions data are only as accurate as the apparatus used to
take them. If the monitoring is not continuous, the measured pollutant
concentration data that are recorded represent only the emissions at a
particular moment in time for a particular location within the stack.
Moving from a concentration sample to an accurate estimate of mass
emissions over time requires calculating mass flow within the stack,
which is sometimes a difficult and uncertain procedure. In addition,
estimating industrial process emissions based on one-time or periodic
measurements usually requires calibrating the monitor using activity
data, requiring that measurement systems be re-assessed whenever routine
operations are altered, including changes to production processes or
volumes. In the end, the activity data itself may provide a more
accurate result at a lower cost than using periodic or unregulated
emissions monitoring data.

To ensure consistency and reliability, reporters using any direct
measurement data should ensure that their measurement systems are
subject to periodic calibration practices. Due to the wide variety of
emission sources and methods for measuring them, this guidance does not
provide specific instruction on calibrating measurement systems for each
emission source discussed herein.

Reporters to the Voluntary Reporting of Greenhouse Gases (1605(b))
Program that directly measure their emissions are expected to follow
internal quality control assessments that verify the accuracy of their
measurement systems. Specific, internationally accepted standard methods
for measuring greenhouse gas emissions exist for some industries. Where
specific methods exist, reporters are encouraged to follow them; where
possible, this guidance refers reporters to readily available, published
authorities that provide specific instruction of this nature.

In the absence of industry-specific standard methods, reporters should
follow internationally accepted, generalized standard methods for
managing and calibrating measurement systems. One such organization
providing guidance for complying with internationally accepted standards
is the International Organization for Standardization (ISO). Reporters
seeking general guidance on methods for managing and calibrating
measurement systems should consult the ISO's guidance document, *ISO
10012 - Measurement Management Systems - Requirements for Measurement
Processes and Measuring Equipment*.[^52]

##### 1.E.3.2 Mass (or Material) Balance

The mass balance method is based on the premise that the mass and energy
content of all components of a substance that go into a process must be
chemically accounted for in some form as output. Estimating emissions
using the mass balance method requires knowledge of the specific
chemical reaction and data on the quantity of raw materials consumed or
product manufactured. This information is used to estimate the mass of
materials from at least one part of the overall chemical reaction.
Emissions can then be calculated using the known molecular proportions
(stoichiometric ratios) of the reaction formula.

The accuracy of mass balance estimates will depend on the precision of
the data available to reporters and the nature of the activity causing
the emission. While the ratio of reactants to products of a particular
chemical reaction is constant, reporters may not have accurate data on
the quantity of either products or reactants associated with a
particular process. For instance, one stage in the production of lime
involves producing quicklime by heating limestone. This process releases
carbon dioxide, as shown in the following equation:

**CaCO~3~ (limestone) + heat → CaO (quicklime) + CO~2.~**

Following the principles of the mass balance method, a reporter could
estimate the mass of carbon dioxide emissions, provided data on the mass
of limestone consumed and the molecular ratio of limestone to carbon
dioxide were available. This assumes, however, that the limestone used
by the facility is 100 percent pure, while limestone purity can actually
be quite variable. If the reporter assumed 100 percent limestone purity
when the facility was processing 85 percent pure limestone, for example,
the result would be an emissions overestimate of nearly 18 percent.

Although for many reporters it is good business practice to collect and
maintain plant-specific activity data, in some instances reporters will
not have access to plant-specific data about the raw materials consumed
or the products manufactured. In those cases, reporters can use default
values that represent common industry standards for relevant parameters.
Mass balance estimates using default values will vary from industry to
industry, depending on how variable the particular default value is
within that industry.

Fugitive emissions from stationary use of a chemical (e.g., refrigerants
or insulators in a sealed environment) are most easily measured when a
known quantity of gas is purchased to replace losses that have occurred
over a given time period. Purchasing refrigerant to re-fill a
refrigerating unit is an example of this situation. In these cases,
fugitive emissions are equal to new purchases/inputs minus the volume of
gas required to satisfy net growth in the equipment stock. Net growth
means the difference between the volumes of new and retiring equipment.
This type of estimation falls under the category of mass balance because
it tracks specific quantities of materials included in a process.

Some industries, including magnesium and aluminum foundries, will
generate emissions through the use and subsequent discharge of
greenhouse or ozone precursor gases. For those industries, emissions are
usually easily estimated, as they are equal to the quantity of gas
purchased minus the quantity recycled over a given time frame. This type
of accounting is also considered a mass balance approach.

##### 1.E.3.3 Inference

If data on raw materials or products are not available, reporters can
estimate emissions indirectly by inference. The Intergovernmental Panel
on Climate Change (IPCC), World Resources Institute/World Business
Council for Sustainable Development (WRI/WBCSD), American Petroleum
Institute (API), U.S. Environmental Protection Agency (EPA), U.S. Energy
Information Administration (EIA), and other authorities on greenhouse
gas estimation methods provide inference-based methodologies to estimate
emissions associated with numerous industrial processes.[^53] The
equations use activity-level data and an associated emissions factor,
according to the following general formula:

**E = AL \* EF**

**Where:**

**E = Emission**

**AL = Activity Level**

**EF = Emissions Factor**

An emissions factor is a representative value that relates the quantity
of a constituent emitted with an activity associated with the production
of that constituent.[^54] The heart of the inference approach to
estimating emissions is the data source that generates this emissions
factor. Inference-based factors are derived from statistical sample data
from a pool of resources that have certain parameters in common with the
process that is being estimated.

The accuracy of an inference-based estimate depends fundamentally on the
accuracy and representativeness of the emissions factor used, and the
natural variability of the process in question. Emissions factors can be
based on a variety of data sources. For instance, an emissions factor
for a given plant can be estimated indirectly from prior direct
observation or measurement of that plant. Alternatively, the emissions
factor could be based on observations or measurements made at a
comparable plant.

Emissions factors can also be based on average measurements for plants
of a specific type, or for an industry in general. Factors of this type
are usually referred to as default emissions factors. Depending on how
default emissions factors are derived, these emissions factors are
usually associated with a more significant margin of error, and can
usually be assumed to provide less accurate estimates.

Inference-based estimates may involve additional arithmetic steps to
estimate either activity level or an emissions factor. For example,
reporters may need to use activity data in conjunction with an
engineering estimate based on measured or default site-specific
operating parameters and model coefficients. This method differs from
direct measurement-based estimation because it does not involve direct
measurement of emissions, but rather uses the direct measurement of, or
site-specific default value for, a related operating parameter. The
operating parameter is used to model an emissions factor. The resulting
emissions factor is used in conjunction with site-specific activity
data, such as quantity of chemicals consumed or output of a product.

Fugitive emissions can be estimated using inference-based methods either
at the facility or at the component level. Facility-level estimates can
be based on published or industry accepted figures of estimated
emissions from similar facilities. Component-level estimates of fugitive
emissions use default emission/leak rates for each of the individual
components used in a facility. Emission estimates for each component are
then summed together to represent all of the emissions from that
facility. Emissions from semiconductor manufacturing can also be
estimated using inference-based methods.

#### 1.E.4 Sector-Specific Emission Estimation Guidance

#### 

Reporters should consult the appropriate references, which are cited
throughout this section, for detailed descriptions of each estimation
methodology. Some of the more useful references include:

-   American Petroleum Institute (API), *Compendium of Greenhouse Gas
    Emissions Estimation Methodologies for the Oil and Gas Industry*
    (February, 2004), web site:
    api-ec.api.org/filelibrary/2004_COMPENDIUM.pdf.

-   California Climate Action Registry, *Industry-Specific Protocols,*
    web site: www.climateregistry.org/PROTOCOLS/.

-   Intergovernmental Panel on Climate Change. *Good Practice Guidance
    and Uncertainty Management in National Greenhouse Gas Inventories*
    (2000), web site: www.ipcc-nggip.iges.or.jp/public/gp/english/.

-   Intergovernmental Panel on Climate Change. *Revised 1996 IPCC*
    *Guidelines for National Greenhouse Gas Inventories* (1997), web
    site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

-   U.S. Energy Information Administration, *Documentation for Emissions
    of Greenhouse Gases in the United 2003* (May 2005), web site:
    www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

-   U.S. Environmental Protection Agency, *Inventory of U.S. Greenhouse
    Gas Emissions and Sinks: 1990 -- 2004* (April 15, 2006), web site:
    http://yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterPublicationsGHGEmissionsUSEmissionsInventory2006.html.

-   U.S. Environmental Protection Agency, Office of Atmospheric
    Programs, Climate Protection Partnerships Division, Climate Leaders
    Program, web site: www.epa.gov/climateleaders/. Specifically,
    *Climate Leaders Greenhouse Gas Inventory Protocol, Sector Specific
    Core Module Guidance* (2003), web site:
    http://www.epa.gov/climateleaders/resources/sector.html.

-   

```{=html}
<!-- -->
```
-   World Resources Institute/World Business Council for Sustainable
    Development (WRI/WBCSD), *GHG Protocol* *Corporate Accounting and
    Reporting Standards, Revised Edition (March 2004)* web site:
    [www.ghgprotocol.org](../www.ghgprotocol.org)*Calculating CO~2~*
    *Emissions from the Production of Ammonia*. ; Calculation Tools:
    httpMenuId=OTAx&doOpen=1&ClickMenu=NoGHG Protocol Initiative
    Downloadable Calculation Tools, Guidance Section," web site:

##### 1.E.4.1 Industrial Processes

**1.E.4.1.1 Adipic Acid Production**

Adipic acid is a white, crystalline powder used primarily for the
manufacture of synthetic nylon fibers; approximately 90 percent of the
adipic acid produced in the United States is used for the manufacture of
nylon 6,6.[^55] Adipic acid is also used in the production of gelatins,
beverages, oils, snack foods, plasticizers for polyvinyl chloride and
polyurethane resins, wire coatings, adhesives, lubricants and dyes. Four
plants produce all of the adipic acid manufactured in the United States.

Nitrous oxide (N~2~O) is the primary greenhouse gas emitted during the
production of adipic acid, which occurs in two stages. In the first
stage, cyclohexanone is oxidized to form a mixture of cyclohexanol and
cyclohexanone. This mixture is then oxidized with nitric acid (HNO~3~)
to form adipic acid, nitrous oxide, and water. Emission rates depend on
specific plant operating parameters and whether or not emissions control
technologies are employed. Nitrous oxide emissions can be significantly
reduced by emission abatement systems, including nitrous oxide-specific
destruction equipment and systems designed to reduce other emissions.
Nitrous oxide destruction systems, for instance, can reduce emissions by
up to 98 percent.[^56]

Reporters are encouraged to use plant-specific, measured estimates of
nitrous oxide emissions. CEM measurements will be assigned a rating of
"A," provided they are calibrated as discussed in subsection 1.E.3.1.
Estimates based on periodic measurements will also be assigned a rating
of "A."

If plant-specific data are not available, reporters can use the IPCC
default uncontrolled emissions factor of 300 kg nitrous oxide per metric
ton adipic acid.[^57] If abatement control technologies are employed,
reporters should amend this uncontrolled emissions factor by accounting
for the destruction and utilization factors[^58] of the control
technology used. Taking these factors into account, N~2~O emissions are
calculated using the following formula:

**N~2~O Emissions = Emissions factor \* Adipic Acid production \***

**\[1 - (N~2~O Destruction factor \* Abatement system utilization
factor)\]**

Table 1.E.1 provides ranges of default destruction-factor and
utilization-factor values for various emission abatement technologies to
adjust the emissions factor to reflect the particular control scenario
for the plant.[^59] Those reporters using these default ranges should
select the lower end of the range for their point values (e.g., those
using defaults and employing catalytic destruction should assume a 90
percent destruction rate and an 80 percent utilization factor).

###### Table 1.E.1. Default N~2~O Destruction and Utilization Factors for Different Abatement Technologies

+----------------------------+---------------------+------------------+
| **Abatement Technology**   | **N~2~O Destruction | **Utilization    |
|                            | Factor**            | Factor**         |
+----------------------------+---------------------+------------------+
| Catalytic Destruction      | 90-95 percent       | 80-98 percent    |
+----------------------------+---------------------+------------------+
| Thermal Destruction        | 98-99 percent       | 95-99 percent    |
+----------------------------+---------------------+------------------+
| Recycle to Phenol          | 98-99 percent       | 90-98            |
| Feedstock                  |                     | percent^\*^      |
+----------------------------+---------------------+------------------+
| Recycle to Adipic Acid     | 90-98 percent       | 80- 98           |
| Feedstock                  |                     | percent^\*\*^    |
+----------------------------+---------------------+------------------+
| ^\*^ For Recycle-to-Nitric |                     |                  |
| Acid Abatement Systems     |                     |                  |
|                            |                     |                  |
| ^\*\*^For                  |                     |                  |
| Recycle-to-Adipic Acid     |                     |                  |
| Abatement Systems          |                     |                  |
|                            |                     |                  |
| Source: Intergovernmental  |                     |                  |
| Panel on Climate Change,   |                     |                  |
| *Good Practice Guidance    |                     |                  |
| and Uncertainty Management |                     |                  |
| for National Greenhouse    |                     |                  |
| Gas Inventories* (2000).   |                     |                  |
+----------------------------+---------------------+------------------+

Estimates using known destruction and abatement factor values for an
abatement system in conjunction with a default emissions rate will be
assigned a rating of "B." Estimates based on default destruction and
abatement factor values will be assigned a rating of "C."

Ratings of methods for estimating N~2~O emissions from adipic acid
production are summarized in Table 1.E.2.

###### *Table 1.E.2. Rating of Estimation Methods for Nitrous Oxide Emissions from Adipic Acid Production*

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Direct measurement, either continuous emissions monitoring or    A
  periodic direct measurements                                     

  Default emissions factors using known destruction and            B
  utilization factors for an abatement technology, with default    
  emissions rate                                                   

  Default emissions factors, using utilization factors, and        C
  reflecting an uncontrolled stream or default factor for an       
  abatement technology                                             
  ---------------------------------------------------------------- ------------

**1.E.4.1.2 Aluminum Production**

Aluminum is produced by electrolytically reducing aluminum oxide via the
reaction:

2AL~2~O~3~ + 3C = 4AL+ 3CO~2~. This process results in emissions of
carbon dioxide and PFCs and can be completed using different
technologies, each of which may feature more than one emission
estimation method. In addition, sulfur hexafluoride may occasionally be
used as a cover gas for special foundry products, with emissions equal
to the volume of consumption. Reporters should begin by familiarizing
themselves with the types of facilities (and their accompanying
processes) for which they will be estimating emissions.

**1.E.4.1.2.1 Carbon Dioxide Emissions from the Smelting Process**

Production of primary aluminum involves two stages: alumina production
and its subsequent reduction to aluminum. In the first stage alumina
(Al~2~O~3~) is produced by calcining ground, purified bauxite ore. While
this stage generates emissions, reporters will not address them in this
section; instead they should refer to the methods outlined in Part C,
"Stationary Combustion."

The second stage, referred to as smelting, involves electrolyzing the
alumina and subsequently reducing it to create primary aluminum. The
simultaneous oxidation of a carbon anode (which serves as the reducing
agent) generates carbon dioxide emissions.

This stage accounts for the majority of the carbon dioxide emissions
emitted directly from aluminum production and can be accomplished using
either of two processes: the Soderberg process or the pre-baked anode
process. Although analogous, these processes differ in the form of the
electrode. Because they also differ in their emission characteristics,
reporters should ascertain the type of facility for which they are
reporting before proceeding with emission estimates.

The most accurate method for estimating carbon dioxide emissions from
primary aluminum production is a mass balance approach based on the
quantity and composition of the reducing agents consumed. Emission
estimates using these data will be assigned a rating of "A."

If data on the composition of the carbon anodes are not available,
WRI/WBCSD provides "industry typical" composition data for pre-baked and
Soderberg anodes.[^60] Alternatively, IPCC provides default emissions
factors for a variety of reducing agents, including pre-baked anodes and
coal electrodes.[^61] Emission estimates calculated using either of
these values in conjunction with data on the quantity of reducing agent
consumed will be assigned a rating of "B."

If reporters do not have access to reducing agent consumption data,
default emission factors for carbon dioxide emissions from primary
aluminum production are provided in Table 1.E.3.

###### Table 1.E.3. Default CO~2~ Emissions Factors for Primary Aluminum Production

  ----------------------------------------------------------------------------------------------- ----------------------------------
  **Process**                                                                                     **Ton CO~2~ per metric ton
                                                                                                  Aluminum**

  Soderberg Process                                                                               1.7

  Pre-baked Anode Process                                                                         1.6

  Source: WRI/WBCSD *GHG Protocol, Guidance to Calculation Tools*, web site:                      
  http://www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=OTAx&doOpen=1&ClickMenu=No   
  ----------------------------------------------------------------------------------------------- ----------------------------------

Emission estimates based on these default values will be assigned a
rating of "B."[^62]

**1.E.4.1.2.2 PFC Emissions from Aluminum Production**

Aluminum smelting also generates emissions of two perfluorocarbons
(PFCs): tetrafluoromethane (CF~4~) and hexafluoroethane (C~2~F~6~).
CF~4~ and C~2~F~6~ are produced when aluminum production is interrupted
due to a lack of alumina near the anode and, as a result of an elevated
voltage, carbon reacts with fluoride salts in the electrolytic bath to
form PFCs. Such interruptions are commonly referred to as "anode
effects." Anode effects are short duration events that occur
periodically on all Hall-Héroult electrolytic cells.

There are three parameters that affect PFC emissions from smelters: (1)
aluminum production, (2) anode effect minutes per cell day (or anode
effect over-voltage for the Pechiney method), and (3) smelter-specific
"slope factors" (or over-voltage coefficients for the Pechiney method).
These three parameters determine the quantity of PFCs emitted per anode
effect minute (or per anode effect over-voltage) per cell day. Both the
IPCC Tier 3b and Tier 2 approaches distinguish between the Slope Method
and the Pechiney Overvoltage Method. The IPCC Tier 3b approach uses
smelter-specific information for each of these parameters, and is
consequently the most accurate approach (other than CEM, which is not
currently used). The IPCC Tier 2 approach uses smelter-specific
information for the first and second parameters, but relies on
technology-specific slope factors for the last. The least accurate IPCC
Tier 1 approach uses smelter-specific information for the first
parameter only.

Chapter 3.3 of IPCC's *Good Practice Guidance*,[^63] "PFC Emissions from
Aluminum Production," contains a detailed discussion of the various
methods. This document, as well as the periodic updates of the IPCC's
*Guidelines for National Greenhouse Gas Inventories*,[^64] is a valuable
source of information on both methods and the most recent default
emissions factors. In addition, the U.S. Environmental Protection Agency
(EPA) and the International Aluminum Institute have developed a Protocol
for measurement of CF~4~ and C~2~F~6~ from primary aluminum
production.[^65] The protocol was produced with the purpose of fostering
consistency in smelter-specific sampling programs and to assist with
developing accurate PFC inventories based on IPCC Tier 3b method.[^66]

There are a number of ways to estimate PFC emissions from anode effects.
The most accurate method is to take representative field measurements
and to use this information to develop smelter-specific slope factors
that reflect either a) the relationship between emissions and anode
effect minutes per cell day (referred to as the Slope method) or b) the
relationship between emissions and anode effect over-voltage (referred
to as the Pechiney Over-voltage method).

To estimate emissions using the Slope method, the slope factor is then
multiplied by the anode effect minutes per cell day and by aluminum
production:

**PFC Emissions / ton Aluminum = Slope \* Anode effect minutes per cell
day**

To estimate emissions using the Pechiney Over-voltage method, an
over-voltage coefficient is multiplied by the anode effect over-voltage
divided by the current efficiency of the aluminum production process:

**PFC Emissions / ton Aluminum =**

**Over-voltage coefficient \* (Anode effect over-voltage / Current
efficiency)**

Emission estimates using either of these methods will be assigned a
rating of "A."

In the absence of smelter-specific slope factors, reporters can estimate
emissions using production data in conjunction with technology-specific
slope factors, anode effect frequency and duration data (if using the
Slope method) or with production data in conjunction with
technology-specific over-voltage coefficients and anode effect
over-voltage. Reporters should consult IPCC's *Good Practice
Guidance*[^67] in order to determine which method is most applicable to
their facility and for the detailed methodology. Emission estimates
using either of these approaches will be assigned a rating of "B."

If anode effect data are unavailable, reporters should use the most
recent default emissions factors available through the IPCC.[^68]
Emissions estimates based on these default values will be assigned a
rating of "C."

**1.E.4.1.2.3 SF~6~ Emissions from Aluminum Production**

Sulfur hexafluoride (SF~6~) is used as a cover gas during the production
of certain aluminum foundry products. It is generally accepted that none
of the sulfur hexafluoride is reacted with or consumed while used, and
that it is all emitted directly into the atmosphere after use.[^69]
Thus, the amount of sulfur hexafluoride emitted from aluminum foundries
is equal to the amount consumed:

**SF~6~ Emissions = SF~6~ Consumption.**

Consumption data can be easily inferred from purchase data. Estimates
based on purchase data will be assigned a rating of "A."

Ratings of methods for estimating emissions from aluminum production are
summarized in Table 1.E.4.

###### Table 1.E.4. Rating of Estimation Methods for Carbon Dioxide, PFC, and Sulfur Hexafluoride Emissions from Aluminum Production

  -----------------------------------------------------------------------------
  **Estimation Method**                                            **Rating**
  ---------------------------------------------------------------- ------------
  **Carbon Dioxide Emissions From The Smelting Process**           

  Mass balance based on quantity and composition of reducing       A
  agents consumed                                                  

  Mass balance based on default anode composition values and data  B
  on quantity of reducing agent consumed                           

  Default emissions factors                                        B

  **PFC Emissions From Aluminum Production**                       

  Smelter-specific slope factors based on representative field     A
  measurements                                                     

  Technology-specific slope factors (or over-voltage               B
  coefficients), anode effect frequency and duration (or anode     
  effect over voltage), and production data                        

  Inference method based on most recent IPCC default emissions     C
  factors                                                          

  **SF~6~ Emissions From Aluminum Production**                     

  Inference method using purchase data                             A
  -----------------------------------------------------------------------------

**1.E.4.1.3 Ammonia Production**

Most ammonia (NH~3~) production processes emit carbon dioxide through
the catalytic reformation of fossil fuels.

Ammonia is produced through a reaction between hydrogen and nitrogen
gases. While nitrogen is available from the atmosphere, hydrogen must be
supplied from a specialized source. Hydrogen can be obtained from the
catalytic reformation of natural gas or other fossil fuels. Nearly all
of the ammonia produced in the United States uses catalytic steam to
reform natural gas. Additional sources include the reformation of other
fossil fuels and byproduct hydrogen streams, as from the electrolysis of
brine to produce chlorine or sodium hydroxide.[^70]

Carbon dioxide emission rates are influenced by a number of factors,
including the carbon content of the reformed fossil fuel, plant
operating characteristics, and the type of emissions control technology
or carbon dioxide recovery mechanisms, if any, employed at the plant
(e.g., capture and use of carbon dioxide in the production of urea).
Accordingly, direct measurement of emissions, for instance, via
continuous emission monitoring, is the most accurate method for
estimating emissions from ammonia production. Estimates based on direct
measurements of emissions, including CEM and periodic direct
measurements will be assigned a rating of "A."

In the absence of direct measurement, there are a number of methods
reporters can use to estimate emissions. The following estimation
methods assume that all of the carbon contained in the feedstock fuel is
released directly to the atmosphere.[^71] Ratings for these estimates
will depend on the data that are available.

Reporters can estimate carbon dioxide emissions using a mass balance
approach based on the carbon content and consumption data for the
feedstock fuel used to produce ammonia. Carbon dioxide emissions are
estimated using the following equation:

**CO~2~ emissions = Consumption ~Feedstock\ fuel~ \* Carbon content
~Feedstock\ fuel~\
\* CO~2~ / carbon ratio**

**Where:**

**CO~2~ / Carbon ratio = 44/12**

Emission estimates using a known value for the carbon content of the
feedstock fuel[^72] will be assigned a quality rating of "B." If
plant-specific data are not available, reporters can use the default
carbon content values for pipeline quality natural gas in the United
States, provided in Table 1.E.5 below.[^73]

###### Table 1.E.5. Carbon Dioxide Emissions Coefficients for U.S. Natural Gas

+-----------------------------+-------------------+-------------------+
| **HHV Btu Content per       | **Emissions       |                   |
| Standard Cubic Foot**       | Coefficient**     |                   |
|                             |                   |                   |
|                             | **(metric tons    |                   |
|                             | per billion       |                   |
|                             | Btu)**            |                   |
+-----------------------------+-------------------+-------------------+
|                             | **CO~2~**         | **Carbon**        |
+-----------------------------+-------------------+-------------------+
| 975 -- 1,000                | 54.01             | 14.73             |
+-----------------------------+-------------------+-------------------+
| 1,000 -- 1,025              | 52.91             | 14.43             |
+-----------------------------+-------------------+-------------------+
| 1,025 -- 1,050              | 53.06             | 14.47             |
+-----------------------------+-------------------+-------------------+
| 1,050 -- 1,075              | 53.46             | 14.58             |
+-----------------------------+-------------------+-------------------+
| 1,075 -- 1,100              | 53.72             | 14.65             |
+-----------------------------+-------------------+-------------------+

**Source**: Energy Information Administration, *Documentation for
Emissions of Greenhouse Gases in the United States 2003* (May, 2005),
web site:
www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

Emission estimates using these values will be assigned a rating of "B."

If plant-specific information is not available, reporters can use a
default emissions factor of 1.26 tons carbon dioxide / ton ammonia
produced.[^74] Emission estimates based on this default value will be
assigned a rating of "C."

Reporters estimating carbon dioxide emissions from ammonia production
should ensure that the feedstock (usually natural gas) is not also
treated as a source of combustion emissions, which would cause double
counting.

Carbon dioxide generated by ammonia plants is sometimes captured for use
as an industrial product (e.g., for urea, dry ice, or use in carbonated
beverages). Any such emissions that are captured and sold or otherwise
exported for use by a separate entity should not be reported by the
capturing entity. If they are subsequently released, they should be
reported by the entity in possession of the material at the time such
gases are emitted. If carbon dioxide from ammonia production is captured
and used by the same entity as an input to another industrial process,
such as urea manufacturing, the carbon dioxide consumed should not be
reported as an emission from ammonia production. Reporters should also
be aware of the potential for fugitive emissions of methane from ammonia
production, either through feedstock (i.e., natural gas) leaks, or
alongside fugitive non-methane volatile organic compounds NMVOC
emissions from the steam reforming process. Reporters should refer to
applicable guidelines and ratings for estimating fugitive emissions as
reported in the Oil and Natural Gas Industries subsection 1.E.4.2.2.

Ratings of methods for estimating carbon dioxide emissions from ammonia
production are summarized in Table 1.E.6.

###### Table 1.E.6. Rating of Estimation Methods for Carbon Dioxide Emissions from Ammonia Production

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Continuous emission monitoring or periodic direct measurement    A

  Mass balance when carbon content of feedstock fuel is known      B

  Mass balance using default carbon content value                  B

  Default emissions factor of 1.26 tons carbon dioxide per ton     C
  ammonia produced                                                 
  ---------------------------------------------------------------- ------------

**1.E.4.1.4 Cement Production**

Cement manufacturing is the largest source of non-combustion,
anthropogenic carbon dioxide emissions resulting from industrial
processes. Cement production releases carbon dioxide both during the
production of clinker (calcination carbon dioxide) and from discarded
bypass and/or cement kiln dust (CKD).

**1.E.4.1.4.1 Carbon Dioxide Emissions from Clinker Production**

Clinker production is the most significant source of greenhouse gas
emissions during the production of cement.[^75] Carbon dioxide is
released when a calcium carbonate (CaCO~3~)-rich substrate such as lime
or chalk is heated, converting the calcium carbonate content to calcium
oxide (CaO) and carbon dioxide (CO~2~). This process is known as
calcination. The calcium oxide is then exposed to a silica-containing
material such as clay, leading to the formation of clinker. "Calcination
carbon dioxide" can be measured in two ways: the clinker method or the
cement method.

The "clinker method" is a mass balance approach based on the quantity of
clinker produced.[^76] Reporters can calculate a "calcination" emissions
factor (tons carbon dioxide released from calcium carbonate per ton
clinker produced) by multiplying the measured calcium oxide content of
the clinker (as a percent) by the molecular ratio of carbon dioxide to
calcium oxide (0.785):

**Calcination CO~2~ Emissions Factor = CaO content \* Molecular ratio of
CO~2~ to CaO**

**Where:**

**CaO Content = CaO content of Clinker (%)**

**Molecular Ratio of CO~2~ / CaO = 0.785**

Multiplying this emissions factor by clinker production data will
provide an estimate of carbon dioxide emissions from calcination:

**Calcination CO~2~ Emissions = Calcination CO~2~ Emissions Factor \*
Clinker Produced**

**Where:**

**Clinker Produced = Tons of Clinker produced**

Estimates based on this approach will be assigned a rating of "A."

Similarly, magnesium carbonate (MgCO~3~) in cement raw materials
decomposes to magnesium oxide (MgO) and carbon dioxide (CO~2~) during
calcination. These emissions can be calculated by measuring the
magnesium oxide content of the clinker.[^77] Reporters can calculate a
"magnesium" emissions factor (tons carbon dioxide released from
magnesium carbonate per ton clinker produced) by multiplying the
measured magnesium oxide content of the clinker (as a percent) by the
molecular ratio of carbon dioxide to magnesium oxide (1.092):

**Magnesium CO~2~ Emissions Factor = MgO content \* Molecular ratio of
CO~2~ to MgO**

**Where:**

**MgO Content = MgO content of Clinker (%)**

**Molecular Ratio of CO~2~ / MgO = 1.092**

Multiplying this emissions factor by clinker production data will
provide an estimate of carbon dioxide emissions from the decomposition
of MgCO~3~:

**Magnesium CO~2~ Emissions = Magnesium CO~2~ Emissions Factor \*
Clinker Produced**

**Where:**

**Clinker Produced = Tons of Clinker produced**

Estimates based on this information will be assigned a rating of "A."

If the calcium oxide or magnesium carbonate content of the clinker is
not known, a default emissions factor of 0.525 metric tons of carbon
dioxide / metric ton clinker can be used.[^78] Emission estimates using
this default value will be assigned a rating of "B."

If the CaO content of the clinker is not known, carbon dioxide emissions
can be estimated using another mass balance approach referred to as the
"cement method."[^79] The cement method relies on information about the
composition and quantity of raw materials consumed (rather than the
clinker produced), the quantity of clinker incorporated into the cement
and the quantity of cement produced. If reporters have access to
reliable information regarding the quantity of clinker in their cement
and the composition of the raw materials used in its production, this
method is as accurate as the clinker method. The data used to calculate
an emissions factor are as follows:

**CO~2~ Emissions per quantity cement produced = Clinker-to-cement ratio
\***

**Raw material-to-clinker ratio \* CaCO~3~ content \* Molecular ratio of
CO~2~ to CaCO~3~**

**Where:**

**Clinker-to-cement ratio = Tons of clinker / ton of cement**

**Raw material-to-clinker ratio = Tons of raw material / ton of
clinker**

**CaCO~3~ Content = Lime content of the raw materials (%)**

**Molecular Ratio of CO~2~ / CaCO~3~ = 0.44**

Carbon dioxide emissions are estimated by multiplying this emissions
factor by the total quantity of cement produced. Emission estimates
using this approach in conjunction with plant-specific raw material
composition and clinker fraction data will be assigned a rating of "A."

If plant-specific data regarding the clinker-to-cement ratio is not
known, reporters can use default clinker and additive fraction values
for different cement production mixes provided in Table 1.E.7.[^80]

###### Table 1.E.7. Clinker Composition Values for Non-Portland Blended Cement Types

  ----------------------------------- ------------- ---- ---- ---- ---- ----
                                                                        

                                                                        

                                                                        

                                                                        

  **Additive Content (Pozzolan +      **Clinker in                      
  Slag) of the Blended Cement         the Cement                        
  (percent)**                         Production                        
                                      Mix                               
                                      (percent)**                       

  10                                  85                                

  20                                  76                                

  30                                  66                                

  40                                  57                                

  75                                  24                                

  Source: Intergovernmental Panel on                                    
  Climate Change, *Good Practice                                        
  Guidance and Uncertainty Management                                   
  for National Greenhouse Gas                                           
  Inventories* (2000).                                                  
  ----------------------------------- ------------- ---- ---- ---- ---- ----

Estimates that use these values will be assigned a rating of "B."

If reliable data on the quantities and composition of the raw materials
used are not available, reporters can use a default emissions factor of
0.499 tons carbon dioxide / ton cement produced.[^81] Emission estimates
relying on this default emissions factor will be assigned a rating of
"C."

**1.E.4.1.4.2 Carbon Dioxide Emissions from Discarded Bypass/Cement Kiln
Dust**

During the production of cement, some of the raw materials entered into
the kiln may not be converted into clinker, generating what is known as
cement kiln dust (CKD). CKD can either be "recycled" back into the
clinker production process, or used for some other application (e.g., as
a soil liming agent, or in road bases). CKD that is landfilled or
discarded instead of being re-used can be another source of carbon
dioxide emissions. Emissions from discarded CKD should not be included
in cement manufacturers' emission inventories, provided it is discarded
outside of the entity's organizational boundaries. If the discarded CKD
eventually lead to emissions, such emissions should be included in the
inventory of the entity in possession of the material at the time the
emissions occur.

Estimates based on direct measurements of emissions will be assigned a
rating of "A." Reporters with plant-specific clinker emissions factors
(see above) and the data on the portion of CKD that is calcined should
consult the WRI/WBCSD GHG Protocol for details on estimating emissions
from discarded CKD.[^82] Estimates based on this methodology are rated
"B."

If specific data on CKD composition and quantities are not available,
reporters can assume carbon dioxide emissions from discarded CKD are
equal to 2 percent of the carbon dioxide emissions from clinker
production.[^83] Estimates based on this method will be assigned a
rating of "C."

Ratings of methods for estimating carbon dioxide emissions from cement
production are summarized in Table 1.E.8.

###### Table 1.E.8. Rating of Estimation Methods for Carbon Dioxide from Cement Production

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  **Carbon Dioxide Emissions From Clinker Production**             

  Mass balance, clinker method, based on measured calcium oxide    A
  content of clinker                                               

  Clinker method based on measured magnesium oxide content of      A
  clinker                                                          

  Default emissions factor (includes emissions from CaO and MgO)   B

  Mass balance, cement method, based on plant-specific raw         A
  material data and clinker content of cement                      

  Default clinker and additive fraction values for appropriate     B
  cement production mix                                            

  Default emissions factor of 0.499 tons carbon dioxide per ton    C
  cement produced                                                  

  **Carbon Dioxide Emissions From Discarded Bypass/Cement Kiln     
  Dust**                                                           

  Direct measurement                                               A

  Plant-specific clinker emissions factors and data on portion of  B
  CKD that is calcined                                             

  Inference based on discarded CKD value, assumed equal to two     C
  percent of CO~2~ from clinker production                         
  ---------------------------------------------------------------- ------------

**1.E.4.1.5 Hydrogen Production**

Hydrogen production is similar, in many respects, to ammonia production.
As in the case of ammonia, a hydrocarbon feedstock (usually natural gas)
is reformed into a carbon monoxide-hydrogen synthesis gas. In this case,
the hydrogen is separated and used for other purposes (usually to boost
light product output in oil refineries; occasionally directly as a
transportation fuel).

For the purposes of the Voluntary Reporting Program, reporters should
only treat carbon dioxide produced as a byproduct of hydrogen production
as an industrial process emission if it is emitted into the atmosphere.
Direct measurement of carbon dioxide emissions from this source would be
rated "A." Reporters may also use mass balance calculations from the
feedstock use of fossil fuels to calculate emissions from this
source.[^84] Estimates based on mass balance calculations will be
assigned a rating of "A."

Ratings of methods for estimating emissions from hydrogen production are
summarized in Table 1.E.9.

###### Table 1.E.9. Rating of Estimation Methods for Carbon Dioxide Emissions from Hydrogen Production

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Direct measurement                                               A

  Mass balance based on feedstock use of fossil fuels              A
  ---------------------------------------------------------------- ------------

**1.E.4.1.6 Iron and Steel Production**

This section covers emissions from the production of iron and steel from
two types of facilities: large, integrated primary iron and steel
plants; and smaller, primary plants. Integrated plants have coking,
smelting and refining capabilities, allowing them to produce iron and
steel from iron ore and raw coal. Smaller primary plants typically
produce iron and steel with coke that is imported from external coking
plants.[^85]

All iron/steel plants use a blast furnace to produce pig iron, also
known as crude iron. In the furnace, raw iron ore is heated in the
presence of carbon and oxygen, reducing it to molten pig iron. Coke is
the usual source of carbon for this process (though coal and natural gas
are also used) and is consumed both as a fuel and as a source of carbon.
Pig iron production is aided in most plants by the addition of a
carbonate flux, such as limestone or dolomite.

Reducing the carbon content of crude iron through oxidation produces
steel. Low-carbon steels are produced in basic oxygen furnaces (BOF),
while high-carbon and alloy steels are produced in electric arc furnaces
(EAF), induction and open-hearth furnaces.

The majority of carbon dioxide emissions from iron and steel production
are generated during the consumption of the reducing agent, and of
additives (typically plastics) used to reduce the quantity of reducing
agent used. Consumption of carbonate fluxes is also a significant source
of carbon dioxide, but these emissions should be calculated using the
methods outlined under "Limestone and Dolomite Use."

In general, the most accurate estimates of emissions from iron and steel
producing facilities will include mass balance calculations of emissions
from the consumption of reducing agents and additives, and the
conversion of iron to steel, corrected for the quantity of carbon
contained in carbon-bearing products exported from the facility. If it
is not possible to account for all of these emissions using
plant-specific data, default values are provided.

**1.E.4.1.6.1 Carbon Dioxide Emissions from Reducing Agent Consumption**

Reducing agent consumption is the primary carbon dioxide emitting
process in iron and steel production. Carbon dioxide emissions from
reducing agent consumption can be estimated by multiplying the mass of
the reducing agent consumed by its carbon content (as a percent) by the
molecular ratio of carbon dioxide to carbon (44/12):

**CO~2~ Emissions ~Reducing\ Agent~ = M ~Reducing\ Agent~ \* CC
~Reducing\ Agent~ \* (44/12)**

**Where:**

**M ~Reducing\ Agent~ = mass of the reducing agent consumed, in tons**

**CC ~Reducing\ Agent~ = carbon content of the reducing agent
(percent)**

**44/12 = molecular ratio of carbon dioxide to carbon**

Emission estimates using known values for the carbon content of the
reducing agent will be assigned a rating of "A."

If specific data on the carbon content of the reducing agent used are
not available, reporters can use the default emissions factors provided
in Table 1.E.10.

###### Table 1.E.10. Default CO~2~ Emissions Factors for Various Reducing Agents

+-------------------------------+--------------------------------------+
| **Reducing Agent**            | **Emissions Factor**                 |
|                               |                                      |
|                               | **(ton CO~2~ / Ton reducing agent)** |
+-------------------------------+--------------------------------------+
| Coke from coal                | 3.1                                  |
+-------------------------------+--------------------------------------+
| Coal                          | 2.5                                  |
+-------------------------------+--------------------------------------+
| Petroleum coke                | 3.6                                  |
+-------------------------------+--------------------------------------+
| Source: Intergovernmental     |                                      |
| Panel on Climate Change,      |                                      |
| *Revised 1996 IPCC Guidelines |                                      |
| for National Greenhouse Gas   |                                      |
| Inventories - Reference       |                                      |
| Manual* (1997) p. 2.26, Table |                                      |
| 2-12.                         |                                      |
+-------------------------------+--------------------------------------+

Emission estimates using these default values will be assigned a rating
of "B."

**1.E.4.1.6.2 Carbon Dioxide Emissions from Furnace Additives**

Iron producers will sometimes introduce additives such as recycled
plastic compounds to the blast furnace to reduce the quantity of coke
used as a reducing agent. Emissions from those additives can be
estimated using the following general equation:

**CO~2~ emissions ~additives~ (tons) = Mass ~additive~ (tons) \*
Emissions factor ~additive~ (ton CO~2~ / ton additive)**

Reporters can use the default emissions factors for common reducing
agent additives provided in Table 1.E.11.

###### Table 1.E.11. Default Emissions Factors for Furnace Additives

  ---------------------------------- ------------------------------------
  **Additive**                       **Ton CO~2~ / Ton additive**

  PVC                                1.62

  PET                                2.24

  PE                                 2.85

  Source: World Resources Institute  
  / World Business Council for       
  Sustainable Development,           
  *Calculating CO~2~ Emissions from  
  the Production of Iron and Steel,* 
  Guidance Section.                  
  ---------------------------------- ------------------------------------

Emission estimates using these default values will be assigned a rating
of "A."

**1.E.4.1.6.3 Carbon Dioxide Emissions from the Conversion of Iron to
Steel**

Carbon dioxide is released when high-carbon pig iron is reduced to
lower-carbon steel. If data on the carbon content of the pig iron and
steel produced are available, reporters should estimate these
emissions.[^86] Carbon dioxide emissions can be estimated by multiplying
the difference between the quantities of carbon contained in the pig
iron and in the steel products by the mass ratio of carbon dioxide to
carbon (44/12), as in the following equation:

**CO~2~ Emissions ~Pig\ iron~ = (Carbon Content ~Pig\ Iron~ - Carbon
Content ~Steel~ ) \* (44/12)**

Emission estimates based on plant-specific carbon contents will be
assigned a rating of "A."

If specific values for the carbon contents of the produced metals are
unavailable, default emissions factors provided in Table 1.E.12 may be
used.

###### Table 1.E.12. Default Carbon Content Values for Various Metals

  -------------- ------------------------------------ --------------------------------- --
                 **Metal**                            **Carbon Content (percent)**      

                 Ore                                  Approximately 0                   

                 Internationally traded crude (pig)   Approximately 4                   
                 iron                                                                   

                 Cast iron products                   Approximately 4                   

                 Steel produced                       0.40                              

  Source**:**                                                                           
  World                                                                                 
  Resources                                                                             
  Institute /                                                                           
  World Business                                                                        
  Council for                                                                           
  Sustainable                                                                           
  Development,                                                                          
  *Calculating                                                                          
  CO~2~                                                                                 
  Emissions from                                                                        
  the Production                                                                        
  of Iron and                                                                           
  Steel,*                                                                               
  Calculation                                                                           
  Tools.                                                                                
  -------------- ------------------------------------ --------------------------------- --

Emission estimates using these default values will be assigned a rating
of "B."

**1.E.4.1.6.4 Carbon Dioxide Emissions from Graphite Electrodes in EAF
Furnaces**

Facilities that produce steel using EAF furnaces should estimate carbon
dioxide emissions from the consumption of graphite electrodes. Reporters
can estimate those emissions using the following emissions factor
approach:

**CO~2~ Emissions ~graphite\ electrodes~ (tons) = Mass
~graphite\ electrodes~ (tons)\
\* Emissions Factor ~graphite\ electrodes~ (tons CO~2~ / ton
electrode)**

Emission estimates using plant-specific graphite electrode emissions
factors will be assigned a rating of "A."

If plant-specific electrode emissions factors are not available,
reporters can estimate emissions from electrode consumption by using a
default value of 1.5 kg CO~2~ per ton steel produced in EAF
furnaces.[^87] This method will be assigned a rating of "B."

**1.E.4.1.6.5 Default Method for Estimating Carbon Dioxide Emissions
from Iron and Steel Production -- All Processes**

If reporters do not have access to the data required to estimate
emissions from the various sources specified above, they can use a
default emissions factor of 1.75 metric tons carbon dioxide per metric
ton of steel,[^88] which includes emissions from all of these sources
for integrated steel facilities. Estimates based on these values will be
assigned a rating of "C."

Ratings of methods for estimating emissions from iron and steel
production are summarized in Table 1.E.13.

###### Table 1.E.13. Rating of Estimation Methods for Carbon Dioxide Emissions from Iron and Steel Production

  --------------------------------------------------------------- ------------
  **Estimation Method**                                           **Rating**

  **Carbon Dioxide Emissions From Reducing Agent**                

  Plant-specific data on reducing agent consumption and its       A
  carbon content                                                  

  Default reducing agent emissions factors                        B

  **Carbon Dioxide Emissions From Furnace Additives**             

  Mass balance using default furnace-additive emissions factor    A

  **Carbon Dioxide Emissions From the Conversion of Iron to       
  Steel**                                                         

  Mass balance based on plant-specific carbon content of pig iron A
  minus plant-specific carbon content of steel                    

  Mass balance based on default carbon content values             B

  **Carbon Dioxide Emissions From Graphite Electrodes in EAF      
  Furnaces**                                                      

  Mass Balance using plant-specific graphite electrode emissions  A
  factors                                                         

  Mass Balance using default emissions factor of 1.5 kg CO~2~ per B
  ton steel produced                                              

  **Carbon Dioxide Emissions - All Processes**                    

  Production times default emissions factor of 1.75 tons CO~2~    C
  per ton of steel                                                
  --------------------------------------------------------------- ------------

**1.E.4.1.7 Lime Production**

Lime production refers to the manufacture of high calcium lime,
dolomitic lime, and hydraulic lime. In the production of calcium lime
and hydraulic lime, carbon dioxide is released by thermally decomposing,
or "calcining," calcium carbonate (CaCO~3~) into lime (CaO) and carbon
dioxide (CO~2~). Dolomitic lime is produced by the calcination of
dolomite (CaCO~3~·MgCO~3~). Carbon dioxide released by the calcination
of CaCO~3~ in the production of lime in the Kraft pulping process need
not be included in emission inventories since the carbon originates in
wood and is considered to be biogenic.

Carbon dioxide emissions from lime production can be calculated using a
mass balance method. The basic stoichiometry of the calcination process
is shown below:

*[High-Calcium and Hydraulic Lime]{.underline}*

**CaCO~3~ + Heat → CaO + CO~2~**

or

*[Dolomitic Lime]{.underline}*

**2 CaCO~3~·MgCO~3~ + Heat → 2 CaO·MgO + 4 CO~2.~**

The stoichiometric weight ratios of carbon dioxide to calcium oxide and
carbon dioxide to magnesium oxide are provided in Table 1.E.14.

###### Table 1.E.14. Stoichiometric Weight Ratio of CO~2~ to CaO and CO~2~ to MgO

  ------------------------- ---------------------------------------------
  **Lime Component**        **Stoichiometric Weight Ratio**

  Calcium oxide (CaO)       0.7848

  Magnesium oxide (MgO)     1.0918

  Source: National Lime     
  Association, *CO~2~       
  Emissions Calculation     
  Protocol for the Lime     
  Industry: English Units   
  Version*, February 2,     
  2005 Revision, 17 pp.     
  ------------------------- ---------------------------------------------

Reporters can calculate an emissions factor for each type of quicklime
and each type of calcined byproduct/waste produced by multiplying the
stoichiometric weight ratios in Table 1.E.14 by the CaO content or for
dolomitic lime, the MgO content, of the lime (as a percent by mass)
produced:

**Emissions Factor = (% Total CaO \* SWR~CO2/CaO~) + (% Total MgO \*
SWR~CO2/MgO~)**

**Where:**

**Emissions Factor =** **tons CO~2~ / ton high calcium, dolomitic or**

**hydraulic lime produced, as appropriate**

**% Total CaO = CaO content of lime as a percent by mass**

**% Total MgO = MgO content of lime as a percent by mass**

**SWR~CO2/CaO~ = Stoichiometric weight ratio of CO~2~ to CaO (0.7848)**

**SWR~CO2/MgO~ = Stoichiometric weight ratio of CO~2~ to MgO (1.0918)**

Total carbon dioxide emissions can then be calculated by multiplying the
emissions factors derived above by the respective quantities of each
type of quicklime and calcined byproduct/waste produced:

**Total Emissions = Quantity Quicklime or Calcined Byproduct/Waste
Produced \* Emissions Factor**

Emission estimates using measured, site-specific values will be assigned
a rating of "A."

If reporters do not have the data required to estimate their own
emissions factor, they can use the default emissions factors provided in
Table 1.E.15.

###### Table 1.E.15. Default CO~2~ Emissions Factors for Lime Production

  ------------------------- ---------------------------------------------
  **Lime Type**             **Default Emissions Factor (tons CO~2~ / ton
                            lime)**

  High Calcium              0.75

  Dolomitic                 0.86

  Hydraulic                 0.59

  Source: Intergovernmental 
  Panel on Climate Change,  
  *Good Practice Guidance   
  and Uncertainty           
  Management for National   
  Greenhouse Gas            
  Inventories* (2000), p.   
  3.22, Table 3.4.          
  ------------------------- ---------------------------------------------

Emission estimates using these default values will be assigned a rating
of "B."

Ratings of methods for estimating emissions from lime production are
summarized in Table 1.E.16.

###### Table 1.E.16. Rating of Estimation Methods for Carbon Dioxide Emissions from Lime Production

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Mass balance using limestone production emissions factor based   A
  on measured lime purity value                                    

  Mass balance using IPCC default emissions factor                 B
  ---------------------------------------------------------------- ------------

**1.E.4.1.8 Limestone and Dolomite Use**

Lime production involves subjecting limestone or dolomite to high
temperatures, which converts it to lime by releasing carbon dioxide.
This process is known as calcination, or calcining; see subsection
1.E.4.1.7, "Lime Production," just above. The following discussion is
intended for use by industries other than lime producers that use
limestone in processes that similarly involve its heating.

The method for estimating carbon dioxide emissions from limestone use is
largely analogous to that used to estimate emissions from lime
production. The primary difference between the methods is that estimates
for lime production are based on the quantity of the calcium-bearing
product (limestone \[CaO~3~\] or dolomite \[CaO·MgO\]), whereas
emissions from limestone and dolomite use are estimated using the
quantity of calcium-bearing raw materials (limestone or dolomite).

Carbon dioxide emissions from limestone and dolomite use can be
estimated with a mass balance approach. As is the case with limestone
production, an emissions factor can be calculated using known
stoichiometric ratios, activity data and fractional purity values. The
most accurate emissions factor is calculated using plant-specific data
on the percent of CaCO~3~ (limestone) or CaCO~3~·MgCO~3~ (dolomite) in
the raw materials consumed, called fractional purity. If the fractional
purity is known, it can be multiplied by the default emissions factors
in Table 1.E.17 to derive a plant-specific emissions factor. Emission
estimates using these data will be assigned a rating of "A." If specific
data about the fractional purity of the raw materials are not available,
reporters can use the default emissions factors listed in Table 1.E.17,
below, which assume 100 percent fractional purity of the raw materials.

###### Table 1.E.17. Default CO~2~ Emissions Factors for Limestone and Dolomite Use

  ---------------------------- ------------------------------------------
  **Raw Material**             **Default Emissions Factor**

  Limestone (CaCO~3~)          440 kg CO~2~ / metric ton limestone

  Dolomite (CaCO~3~· MgCO~3~)  477 kg CO~2~ / metric ton dolomite

  Source: Intergovernmental    
  Panel on Climate Change,     
  *Revised 1996 IPCC           
  Guidelines for National      
  Greenhouse Gas Inventories - 
  Reference Manual* (1997) p.  
  2.10.                        
  ---------------------------- ------------------------------------------

Estimates using these values will be assigned a rating of "B."

Ratings of methods for estimating emissions from limestone and dolomite
use are summarized in Table 1.E.18.

###### Table 1.E.18. Rating of Estimation Methods for Carbon Dioxide Emissions from Limestone and Dolomite Use

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Mass balance using plant-specific emissions factor based on      A
  limestone and dolomite content of the raw material consumed      

  Mass balance using IPCC default emissions factor                 B
  ---------------------------------------------------------------- ------------

**1.E.4.1.9 Methanol Production**

Methanol production is similar to ammonia production (see section
above), in that methanol production begins with reforming a hydrocarbon
feedstock (usually natural gas) into a carbon monoxide-hydrogen
synthesis gas. In this case, however, most of the carbon is embodied in
the product (CH~4~O). Methanol in the United States is mostly used as a
gasoline additive, though there is also a large market for methanol as a
chemical feedstock.

For the purposes of the Voluntary Reporting Program, incidental carbon
dioxide emissions from methanol production should be reported as
emissions, although the carbon embodied in the methanol itself should
*not* be reported as an emission. The party that combusts the methanol
is responsible for emissions of the carbon in the methanol. Methanol in
the gasoline pool (either directly or in the form of Methyl Tertiary
Butyl Ether \[MTBE\]) is implicitly included in the emissions factor for
motor gasoline, and is the responsibility of transportation sector
users. See Part D, "Mobile Sources," for guidance on estimating
emissions from transportation activities.

Direct measurement of carbon dioxide emissions from the production of
methanol, possibly via continuous emission monitoring, would be rated
"A." Reporters may use mass balance calculations (carbon content of
feedstock less carbon content of methanol) to estimate incidental carbon
dioxide losses/emissions from this source. Estimates based on mass
balance calculations will be assigned a rating of "B."

Methanol production also yields small volumes of methane emissions. The
IPCC provides a default emissions factor of two grams methane per
kilogram of methanol produced.[^89] Reporters may use these default
factors when calculating methane emissions from methanol production and
will be assigned a rating of "B." Reporters that are able to directly
measure methane emissions during methanol production will receive an "A"
rating.

Ratings of methods for estimating emissions from methanol production are
summarized in Tables 1.E.19 and 1.E.20 below.

###### Table 1.E.19. Rating of Estimation Methods for Carbon Dioxide Emissions from Methanol Production

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Continuous emissions monitoring or other direct measurement      A

  Mass balance accounting for carbon content of feedstock fuel     B
  minus carbon content of methanol                                 
  ---------------------------------------------------------------- ------------

###### Table 1.E.20. Rating of Estimation Methods for Methane Emissions from Methanol Production

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Direct measurement                                               A

  Use of IPCC provided default factors                             B
  ---------------------------------------------------------------- ------------

**1.E.4.1.10 Methane Emissions from the Production of Other
Petrochemicals**

The production of carbon black, ethylene, ethylene dichloride and
styrene all generate small amounts of methane emissions. Default factors
for estimating emissions from production of these petrochemicals are
provided below in Table 1.E.21. Reporters may use these default factors
when calculating methane emissions from methanol production and will be
assigned a rating of "B." Reporters that are able to directly measure
methane emissions during petrochemical production will receive an "A"
rating.

###### Table 1.E.21. Default Emissions Factors for Methane Emissions from Petrochemical Production

+----------------------------------------+-----------------------------+
| **Petrochemical**                      | **Methane Emissions**       |
|                                        |                             |
|                                        | **(Grams per Kilogram of    |
|                                        | Production**                |
+----------------------------------------+-----------------------------+
| Carbon Black                           | 11                          |
+----------------------------------------+-----------------------------+
| Ethylene                               | 1                           |
+----------------------------------------+-----------------------------+
| Ethylene Dichloride                    | 0.4                         |
+----------------------------------------+-----------------------------+
| Styrene                                | 4                           |
+----------------------------------------+-----------------------------+

Source: Intergovernmental Panel on Climate Change, *Revised IPCC
Guidelines for National Greenhouse Gas Inventories* (1997), p.2.6. web
site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

###### Table 1.E.22. Rating of Estimation Methods for Methane Emissions from Petrochemical Production

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Continuous emissions monitoring or other Direct measurement      A

  Use of IPCC provided default factors                             B
  ---------------------------------------------------------------- ------------

**1.E.4.1.11 Nitric Acid Production**

Nitric acid (HNO~3~) is a primary ingredient of certain nitrogen-based
synthetic fertilizers. Other important applications include adipic acid
production, production of explosives, metal etching, and processing of
ferrous metals. The primary greenhouse gas emitted from the production
of nitric acid is nitrous oxide (N~2~O). Nitrous oxide is released
during the high-temperature catalytic oxidation of ammonia (NH~3~). In
addition to nitrous oxide, this oxidation reaction can also generate
smaller quantities of non-combustion oxides of nitrogen (NO~x~).

Emissions from nitric acid production vary significantly from plant to
plant. Factors that affect emission rates include process conditions,
plant technology and design, whether or not an emission abatement
technology is used, and the frequency with which that technology is
employed.

Continuous emission monitoring (CEM) provides the most accurate estimate
of plant emissions. Ideally, a CEM estimate will account for emissions
from confined streams (e.g., pollutants in flue gas) as well as from
uncontrolled streams. If information for pollutant levels in the
uncontrolled streams is not available, monitoring confined streams alone
will suffice. Emission estimates using CEM will be assigned a rating of
"A."

If CEM is not available, emissions can be estimated using an emissions
factor (or emission rate) approach. For nitric acid plants, this
approach must account for emission rates, the efficacy of abatement
technologies and the frequency with which they are employed (where
applicable). The most accurate emission rate estimates are based on
direct, periodic measurements of plant emissions. Such measurements must
be made whenever the plant undergoes a change that might alter emission
rates. Emission estimates based on emissions factors derived from
periodic direct measurements will be assigned a rating of "A."

Reporters who are unable to acquire plant-specific emission information
can use a default emissions factor of either 2 or 9.5 kg N~2~O/metric
ton nitric acid for plants with or without non-selective catalytic
reduction (NSCR) controls on N~2~O emissions, respectively.[^90]
Estimates based on default values that are publicly documented and have
been widely reviewed and adopted by a public agency, a standards-setting
organization or an industry group such as the IPCC, U.S. EPA, or API
will be assigned a "B" rating. Estimates based on other published
default values will be assigned a rating of "C."

Ratings of methods for estimating emissions from nitric acid production
are summarized in Table 1.E.23.

###### Table 1.E.23. Rating of Estimation Methods for Nitrous Oxide Emissions from Nitric Acid Production

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Continuous emissions monitoring                                  A

  Emissions factors based on direct, periodic measurement of plant A
  emissions                                                        

  Default emissions factors for uncontrolled and non-selective     B
  catalytic reduction control technologies that are publicly       
  documented and have been widely reviewed and adopted by a public 
  agency, a standards-setting organization or an industry group    

  Other default emissions factors for uncontrolled and             C
  non-selective catalytic reduction control technologies           
  ---------------------------------------------------------------- ------------

**1.E.4.1.12 Soda Ash Production and Use**

**1.E.4.1.12.1 Soda Ash Production**

There are four manufacturing processes employed to produce soda ash
(Na~2~CO~3~): monohydrate carbonation, sesquicarbonate carbonation,
direct carbonation, and the Solvay process. The Solvay process, which
synthesizes soda ash from a series of materials and reactions, generates
no direct carbon dioxide emissions. Emissions from stationary combustion
and the use of coke to facilitate these processes, however, should be
estimated and should be accounted for separately.[^91]

The first three of these processes, which account for about 25 percent
of world soda ash production, generate carbon dioxide emissions during
the chemical transformation of the naturally occurring ore, trona, into
Soda Ash. In the absence of direct measurements, reporters can use an
emissions factor derived from the chemical reaction of the production of
soda ash from trona:

**Na~2~CO~3~·NaHCO~3~·2H~2~O + Heat → 3 Na~2~CO~3~ + 5 H~2~O + CO~2.~**

*(trona) (soda ash)*

One ton of carbon dioxide is generated for every 10.27 tons of trona
consumed. Reporters can thus use the following carbon dioxide emissions
factor for soda ash production:

**Emissions Factor~Production~ = 0.097 tons CO~2~ / ton trona consumed**

Emission estimates based on this emissions factor will be assigned a
rating of "A."

**1.E.4.1.12.2 Soda Ash Use**

Soda ash is used in a variety of industrial processes, including the
manufacturing of glass, soap, detergents, and for flue gas
desulfurization. Carbon dioxide emission rates from soda ash use are
also based on stoichiometric ratios, which indicate that one molecule of
carbon dioxide is emitted per molecule of soda ash consumed. Reporters
can use the following carbon dioxide emissions factor for soda ash use,
which is based on the molecular weight ratio of carbon dioxide to soda
ash:[^92]

**Emissions Factor ~Use~ = 0.415 tons CO~2~ / ton Na~2~CO~3~**

Emission estimates based on this emissions factor will be assigned a
rating of "A."

Ratings of methods for estimating emissions from soda ash production and
use are summarized in Table 1.E.24.

###### Table 1.E.24. Rating of Estimation Methods for Carbon Dioxide Emissions from Soda Ash Production and Use

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  **Soda Ash Production**                                          

  Emissions factor based on production of soda ash from trona      A

  **Soda Ash Use**                                                 

  Emissions factor based on molecular weight ratio of carbon       A
  dioxide to soda ash                                              
  ---------------------------------------------------------------- ------------

##### 1.E.4.2 Energy

**1.E.4.2.1 Coal Mining**

The principal greenhouse gas associated with coal mining is methane.
Carbon dioxide and nitrous oxide are also emitted but in relatively
small amounts. Methane is produced in the same geologic processes that
produce coal, and therefore exists in varying degrees in its presence.
The methane is stored in the coal pores (open spaces) and in the cracks
and fractures within the coal bed.

Carbon dioxide emitted directly from the combustion of fossil fuels by
mining equipment or indirectly from the consumption of electricity for
mining activities should be estimated and reported according to the
guidelines in Parts C and E, respectively. The methods outlined here
focus exclusively on estimating methane emissions from coal mining.

The rank[^93] of the coal determines the quantity of methane generated.
Once generated, the amount of methane stored is controlled by the
pressure and temperature of the coal seam and by other, less
well-defined characteristics.[^94] High coal ranks, such as anthracite
and bituminous coal, contain more methane than low coal ranks, such as
lignite (brown coal). Depth under ground is important, because it
affects the pressure and temperature of the coal seam, which in turn
determines how much methane is generated during coal formation. All else
being equal, if two coal seams have the same rank, the deeper seam will
hold larger amounts of methane because the pressure is greater at lower
depths. As a result, the methane emissions factors for surface-mined
coal are generally lower than for underground mining.

As coal is mined, the pressure surrounding the stored methane decreases,
allowing much of it to be released into the operating coal mine (in the
case of an underground mine) or into the atmosphere (in the case of a
surface mine). The methane remaining in the coal pores is emitted when
the coal is transported and pulverized for combustion.

**1.E.4.2.1.1 Processes that Produce Methane**

To estimate the amount of methane emitted during coal mining, it is
useful to segment the broader category of mining and processing into
five distinct subcategories, as listed below.[^95]

1)  *Ventilation Systems in Underground Mines*. Methane in
    concentrations over 5 percent is explosive and presents a mortal
    danger to coal miners. To meet safety standards set by the Mine
    Safety and Health Administration (MSHA) requiring levels of methane
    concentration to be maintained well below the 5-percent threshold,
    mine operators use large fans to provide a steady airflow across the
    mine face and ventilate the mine shaft. These ventilation systems
    may release substantial quantities of methane in the fan exhaust.

2)  *Degasification Systems in Underground Mines*. When the volume or
    concentration of gas in underground mines is too high to be
    practically reduced to safe levels by standard ventilation
    techniques, or if gas can be cost-effectively recovered for
    subsequent energy use, degasification systems are employed.
    Degasification may take place before mining or may take other forms,
    such as gob-wells or in-mine horizontal boreholes. Methane captured
    by degasification systems may be vented, flared, or recovered for
    energy.

3)  *Surface Mines*. Because coal mined from the surface has formed at
    lower temperature and pressure than coal from underground mines, its
    methane content is lower. Further, because the coal is located near
    the surface, the associated methane has had greater opportunity to
    migrate to the atmosphere before mining.

4)  *Post-Mining Emissions*. A portion of the methane emitted from coal
    mining comes from post-mining activities such as coal processing,
    transportation, and use. Coal processing involves the breaking,
    crushing, and thermal drying of coal, making it acceptable for sale.
    Methane is released mainly because the increased surface area allows
    more methane to desorb from the coal. Transportation of the coal
    contributes to methane emissions, because methane desorbs directly
    from the coal to the atmosphere while in transit (e.g., in railroad
    cars).[^96] Prior to combustion by end-users, coal may be
    pulverized, which also releases methane emissions.

5)  *Methane Recovery for Energy*. In some cases methane is emitted from
    coal mines in sufficiently high volumes and concentrations to permit
    commercial recovery of the gas as pipeline gas, power generation
    fuel, or for mine site uses. Because coal mine methane recovered
    commercially is combusted, the quantities recovered are subtracted
    from estimates of total coal mine methane emissions.

**1.E.4.2.1.2 Emission Estimation Methods**

Methane emissions from coal mines may be either directly monitored at
the mine, or estimated based on the amount of coal produced and the type
of mine being utilized. Where methane emissions are directly monitored,
those direct measurements should be used first. Where direct monitoring
does not exist, the indirect estimation methods detailed below should be
used. Direct measurements will be more accurate than indirect
measurements and would thus receive a higher rating, as indicated in
Table 1.E.27, below.

Further discussion of the processes that produce methane and the
associated methods to estimate emissions can be found in the IPCC's
*Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories,*
EPA's *Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 --
2001* (2003), and EIA's *Documentation for Emissions of Greenhouse Gases
in the United States 2002* (2004) (for complete references, see Section
1.E.4, above).

*1.E.4.2.1.2.1 Direct Measurements*

[1.E.4.2.1.2.1.1 Underground Mines with Detectable
Emissions]{.underline}

Methane concentration and airflows from the ventilation systems of
underground mines that have detectable methane concentrations are
monitored on a quarterly basis by MSHA.[^97] Underground mining
operations with detectable emissions should therefore report their
measured ventilation-related methane emissions directly, while also
accounting for those emissions that are not included in the ventilation
process (e.g., degasification and post-mining).

[1.E.4.2.1.2.1.2 Degasification Emissions]{.underline}

The MSHA does not monitor degasification systems, but a mining operation
may nevertheless collect these data, especially if the methane is
subsequently captured and used for a productive purpose such as power
generation or heat production. If direct measurements are available,
they should be used first. In those cases where degasification emissions
are not monitored, an indirect estimate should be made using
methodologies described below.

*1.E.4.2.1.2.2 Indirect Estimation*

[1.E.4.2.1.2.2.1 Degasification in Underground Mines]{.underline}

Total underground methane emissions are composed of ventilation system
emissions and degasification system emissions. As mentioned previously,
ventilation systems with detectable emission levels are monitored by
MSHA directly, and some degasifications systems' emissions are
monitored.

To estimate emissions from degasification systems that do not directly
monitor emissions, an emissions factor based on total underground
emissions (ventilation + gasification) is used. For coal mines employing
gob wells and horizontal boreholes, it is assumed that degasification
emissions account for 40 percent of the total methane liberated from the
mine.[^98] Therefore, the amount of methane emitted from the ventilation
system should be multiplied by 1.667 to yield total (ventilation +
degasification) emissions. Once total emissions are estimated,
ventilated emissions can be subtracted from total emissions to derive
estimated degasification emissions.

Some mining operations engage in advance degasification of underground
coal seams prior to mining. The operator drills wells and extracts
methane from the coal seam, in some cases years before the seam is
actually mined. The extracted methane is often captured and sold
commercially.

Captured gas, or its byproduct, is recorded as an emission in the
inventory of the entity in possession of the gas at the time of its
release into the atmosphere. If the methane is combusted, the carbon
dioxide emissions from the combustion are considered an emission in the
year of combustion. If the methane is vented, it is considered a methane
emission in the year of venting.

[1.E.4.2.1.2.2.2 Surface Mines and Post-Mining Operations]{.underline}

Because emissions from U.S. surface mines and from post-mining
operations, whether underground or surface, are not systematically
measured, estimates must be used instead. To estimate methane emissions
from surface mines and post-mining operations, reporters can multiply
the amount of coal produced at a given mine in one reporting year times
a region-specific emissions factor (Table 1.E.25), as shown in the
following equation. To convert from volume to mass, the density of
methane at 20 degrees Celsius and 1 atmosphere of pressure should be
used: 0.418 pounds per cubic foot.

**Volume of Methane Produced = Mass of Coal Produced\
\* CH~4~ Volumetric Emissions Factor**

The surface mining emissions factor is estimated as twice the *in
situ*[^99] methane content in the basin, and the post-mining emissions
factor is estimated to be 32.5 percent of the *in situ* methane content
in the basin. Region-specific emissions factors are listed in Table
1.E.25, and coal basins and states are presented in Table 1.E.26.[^100]

###### Table 1.E.25. Coal Surface and Post-Mining Methane Emissions Factors (ft^3^/short ton)

  ------------------------ ------------- ----------------- ------------- --------------- ----------------
  **Basin**                **Average\                      **Factors**                   
                           *in situ*                                                     
                           Content**                                                     

                           **Surface**   **Underground**   **Surface     **Post-Mining   **Post Mining
                                                           Mine**        Surface**       Under-ground**

  Northern Appalachia      59.5          138.4             119.0         19.3            45.0

  Central Appalachia (WV)  24.9          136.8             49.8          8.1             44.5

  Central Appalachia (VA)  24.9          399.1             49.8          8.1             129.7

  Central Appalachia (E    24.9          61.4              49.8          8.1             20.0
  KY)                                                                                    

  Warrior                  30.7          266.7             61.4          10.0            86.7

  Illinois                 34.3          64.3              68.6          11.1            20.9

  Rockies (Piceance Basin) 33.1          196.4             66.2          10.8            63.8

  Rockies (Unita Basin)    16.0          99.4              32.0          5.2             32.3

  Rockies (San Juan Basin) 7.3           104.8             14.6          2.4             34.1

  Rockies (Green River     33.1          247.2             66.2          10.8            80.3
  Basin)                                                                                 

  Rockies (Raton Basin)    33.1          127.9             66.2          10.8            41.6

  N. Great Plains          5.6           15.8              11.2          1.8             5.1

  West Interior (Forest    34.3          64.3              68.6          11.1            20.9
  City, Cherokee Basins)                                                                 

  West Interior (Arkoma    74.5          331.2             149.0         24.2            107.6
  Basin)                                                                                 

  West Interior (Gulf      33.1          127.9             66.2          10.8            41.6
  Coast Basin)                                                                           

  Northwest (AK)           5.6           160.0             11.2          1.8             52.0

  Northwest (WA)           5.6           47.3              11.2          1.8             18.9

  Sources: U.S. Bureau of                                                                
  Mines, "Results of the                                                                 
  Direct Method                                                                          
  Determination of the Gas                                                               
  Contents of U.S. Coal                                                                  
  Basins," Circular 9067                                                                 
  (1986); U.S. Department                                                                
  of Energy, *Methane                                                                    
  Recovery from Coalbeds:                                                                
  A Potential Energy                                                                     
  Source*, DOE/METC/83-76                                                                
  (1983); and Gas Research                                                               
  Institute, "A Geologic                                                                 
  Assessment of Natural                                                                  
  Gas from Coal Seams,"                                                                  
  Topical Reports                                                                        
  (1986-1988).                                                                           
  ------------------------ ------------- ----------------- ------------- --------------- ----------------

###### Table 1.E.26. Coal Basins and States

  -------------------------- --------------------------------------------
  **Basin**                  **State**

  Northern Appalachia Basin  Maryland, Ohio, Pennsylvania, West Virginia
                             North

  Central Appalachia Basin   Kentucky East, Tennessee, Virginia, West
                             Virginia South

  Warrior Basin              Alabama, Mississippi

  Illinois Basin             Illinois, Indiana, Kentucky West

  S. West / Rockies Basin    Arizona, California, Colorado, New Mexico,
                             Utah

  N. Great Plains Basin      Montana, North Dakota, Wyoming

  West Interior Basin        Arkansas, Iowa, Kansas, Louisiana, Missouri,
                             Oklahoma, Texas

  Northwest Basin            Alaska, Washington

  Source: U.S. Environmental 
  Protection Agency,         
  *Inventory of U.S.         
  Greenhouse Gas Emissions   
  and Sinks: 1990 -- 2003*   
  (April 15, 2005).          
  -------------------------- --------------------------------------------

[1.E.4.2.1.2.2.3 Accounting for Underground Mines Without Detectable
Emissions from Ventilation Systems]{.underline}

Methane concentrations in ventilation air below 0.1 percent are
undetectable with the measurement equipment used by MSHA, although MSHA
requires all active mines (including those with undetectable methane
levels) to vent at a minimum rate of 3,000 cubic feet of air per minute.
Operators with mines that show undetectable levels of methane
concentration in ventilation air should thus calculate their ventilation
emissions by multiplying a flow rate of 3,000 cubic feet per minute by
an assumed methane concentration of 0.05 percent to derive a methane
emissions flow rate.[^101] Reporters can convert the flow rate to an
annual emissions estimate with the following formula:

**Annual CH~4~ emissions = Ventilation flow rate \* CH~4~ concentration
\* Min/Hour \* Hours/Year**

that is,

**Annual CH~4~ emissions = 3,000 ft^3^/min \* 0.05% CH~4~ \* 60 \* 8760
= 788,400 ft^3^ CH~4~**

**1.E.4.2.1.3 Methane Recovery for Energy**

Any mining operation that captures or combusts methane and prevents its
emission into the atmosphere (usually for combustion in power or heat
generation) should ensure that total emissions account for captured
methane and carbon dioxide emissions from combustion. The captured
methane should not be counted in the inventory but the carbon dioxide
from combusting the captured methane should be counted in the inventory
of the entity in possession of the methane at the time of its
combustion, following the guidance in Part C, "Stationary Combustion."

If direct measurements exist, then these should be used to determine the
quantity of captured or combusted methane emissions. If direct
measurements do not exist, then estimates can be made based on records
of methane usage or sale to another entity. For example, if used for
electricity generation, the amount of electricity produced, along with
information about the generator, can be used to estimate the amount of
methane consumed.

**1.E.4.2.1.4 Emissions Summation**

For underground mines, the total methane emissions that should be
reported are:

1.  Ventilation emissions from mines with detectable methane
    concentrations (directly measured).

2.  Degasification emissions (directly measured where possible;
    otherwise using default emissions factor based on measurements of
    ventilation emissions).

3.  Post-mining operations (using default emissions factor based on mass
    of coal produced).

4.  Estimation from mines with undetectable methane concentrations
    (using indirect estimate based on MSHA regulatory minimums).

5.  Recovered methane emissions (directly measured where possible;
    otherwise using estimates based on usage or sales).

For surface mines, the total methane emissions that should be reported
are:

1.  Surface mining (using default emissions factor based on mass of coal
    produced).

2.  Post-mining operations (using default emissions factor based on mass
    of coal produced).

Ratings of methods for estimating emissions from coal mining operations
are summarized in Table 1.E.27.

###### Table 1.E.27. Rating of Estimation Methods for Methane Emissions from Coal Mining (all sources)

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Direct measurement                                               A

  Direct measurement augmented by indirect estimates based on      B
  default emissions factors                                        

  Indirect estimates based on default emissions factors            C
  ---------------------------------------------------------------- ------------

**1.E.4.2.2 Oil and Natural Gas Industries**

The oil and natural gas industries are multifaceted industries that
generate substantial quantities of greenhouse gas emissions from a
variety of sources during production, processing, transportation, and
distribution activities. Methods for estimating emissions from oil and
natural gas activities are quite varied. Reporters are likely to employ
all of the available estimation methods at some point if attempting to
accurately and comprehensively estimate emissions from either industry
in their entirety. Due to the extensive nature of emission sources and
estimation methods, this section does not attempt to exhaustively
enumerate methods for estimating greenhouse gas emissions from the oil
and natural gas industries. Instead, reporters should use this section
as a guide to the sources of emissions in these industries and the
methods available to estimate them. Reporters should plan on referencing
established, published authorities for details on estimation
methods.[^102]

Types of emission from these industries include process emissions,
fugitive emissions, and emissions from stationary combustion.[^103] The
majority of these emissions are fugitive emissions. Common sources of
fugitive emissions include exploration, handling, processing,
production, storage, transportation, non-productive combustion (e.g.,
flaring[^104]), and maintenance and turnaround activities, both
scheduled and unscheduled. Process vents and non-combustion stacks are
another common source of emissions from the natural gas industry. In
contrast to fugitive emissions, those sources tend to be concentrated
and relatively easy to identify.

Methane is the principal non-combustion greenhouse gas emitted by both
the natural gas and the oil industries. The majority of emissions from
the oil industry are fugitive methane emissions from production
processes. As the principal component of natural gas, methane emissions
are associated with nearly all aspects of the natural gas industry.

Carbon dioxide emissions can be emitted in significant quantities from a
limited number of processes, such as sour gas processing, or in
instances where natural gas streams are particularly rich in carbon
dioxide. Nitrous oxide is also emitted from a number of activities, but
usually in relatively low concentrations.

Emission estimation methods for the oil and natural gas industries vary
widely in their scope, accuracy and involvement. As such, the method
chosen by reporters will depend largely on the data, resources, time,
and money available to them. Due to the large number and diversity of
activities associated with each industry, the IPCC recommends
disaggregating overall activities into subcategories and estimating
emissions separately for each, as appropriate to their level of
emissions and the resources available for each. Table 1.E.28 shows the
industry segments and subcategories identified by the IPCC.

###### Table 1.E.28. IPCC Categorization of Segments and Subcategories of the Natural Gas and Oil Industries

+------------------------------------+---------------------------------+
| **Industry Segment**               | **Subcategories**               |
+====================================+=================================+
| Wells                              | Drilling                        |
|                                    |                                 |
|                                    | Testing                         |
|                                    |                                 |
|                                    | Servicing                       |
+------------------------------------+---------------------------------+
| Gas Production                     | Dry Gas                         |
|                                    |                                 |
|                                    | Sweet Gas                       |
|                                    |                                 |
|                                    | Sour Gas                        |
+------------------------------------+---------------------------------+
| Gas Processing                     | Sweet Gas Plants                |
|                                    |                                 |
|                                    | Sour Gas Plants                 |
|                                    |                                 |
|                                    | Deep-cut Extraction Plants      |
+------------------------------------+---------------------------------+
| Gas Transmission and Storage       | Pipeline Systems                |
|                                    |                                 |
|                                    | Storage Facilities              |
+------------------------------------+---------------------------------+
| Gas Distribution                   | Rural Distribution              |
|                                    |                                 |
|                                    | Urban Distribution              |
+------------------------------------+---------------------------------+
| Liquefied Gases Transport          | Condensate                      |
|                                    |                                 |
|                                    | Liquefied Petroleum Gas (LPG)   |
|                                    |                                 |
|                                    | Liquefied Natural Gas (LNG)     |
+------------------------------------+---------------------------------+
| Oil Production                     | Conventional Oil                |
|                                    |                                 |
|                                    | Heavy Oil - Primary Production  |
|                                    |                                 |
|                                    | Heavy Oil - Enhanced Production |
|                                    |                                 |
|                                    | Bitumen                         |
|                                    |                                 |
|                                    | Synthetic Crude Oil from Oil    |
|                                    | Sands                           |
|                                    |                                 |
|                                    | Synthetic Crude Oil from Oil    |
|                                    | Shales                          |
+------------------------------------+---------------------------------+
| Oil Upgrading                      | Bitumen                         |
|                                    |                                 |
|                                    | Heavy Oil                       |
+------------------------------------+---------------------------------+
| Waste Oil Reclaiming               | None                            |
+------------------------------------+---------------------------------+
| Oil Transport                      | Marine                          |
|                                    |                                 |
|                                    | Pipelines                       |
|                                    |                                 |
|                                    | Tanker Trucks and Rail Cars     |
+------------------------------------+---------------------------------+
| Oil Refining                       | Heavy Oil                       |
|                                    |                                 |
|                                    | Conventional and Synthetic      |
|                                    | Crude Oil                       |
+------------------------------------+---------------------------------+
| Source: Intergovernmental Panel on |                                 |
| Climate Change, *Good Practice     |                                 |
| Guidance and Uncertainty           |                                 |
| Management for National Greenhouse |                                 |
| Gas Inventories* (2000).           |                                 |
+------------------------------------+---------------------------------+

The most comprehensive approach to estimating emissions from the natural
gas and oil industries is to use a rigorous, site-specific, bottom-up
estimate that accounts for emissions from each of the segments described
above. This will require a significant commitment of time and resources,
expert analysis, and will potentially require interaction and
information sharing with industry and regulatory agencies outside of the
reporting entity. Information typically required for this type of
analysis includes:[^105]

-   Detailed inventories of the amount and types of process
    infrastructures (e.g., wells, minor field installations, and major
    production and processing facilities).

-   Production disposition analysis (e.g., oil and gas production;
    vented, flared and re-injected volumes of gas; fuel gas
    consumption).

-   Accidental releases (e.g., well blow-outs and pipeline ruptures).

-   Typical design and operating practices and their impact on the
    overall level of emission control.

Reporters will use this information in conjunction with a variety of
other data and methods in order to estimate emissions. Relevant
estimation methods include emissions factor/inference-based estimates,
empirical correlations, process simulations (including a variety of
software applications available), and extrapolation using additional
field measurements.[^106]

Emissions factors and other estimation data for the natural gas and oil
industries are continually updated and modified. Reporters should
consult industry literature to ensure that they are using the most
up-to-date methods and information possible. Important resources for
reporters from these industries include the EPA's *Compilation of Air
Pollutant Emission Factors, Version 5, AP-42* for the petroleum
industry;[^107] the American Petroleum Institute's standards and
technical publications, statistical reports and regulatory
reports;[^108] EPA's *Emissions Inventory Improvement Program, Volume
Eight - Greenhouse Gas Emissions,* Chapter 3, "Methods for Estimating
Methane Emissions from Natural Gas and Oil Systems;"[^109] and EIA's
"*Documentation for Emissions of Greenhouse Gases in the United States
2003."*[^110]

Additionally, the American Petroleum Institute's *Compendium of
Greenhouse Gas Emission Estimation Methodologies for the Oil and Gas
Industry*[^111] discusses a variety of methods and resources for
estimating emissions from the following sources:

Fugitive emissions:

-Flaring CH~4~

-Storage Tank Flashing Losses CH~4~, CO~2~

-Transportation Loading CH~4~

-Ballasting CH~4~

-Losses During Transit CH~4~

-Well Testing CH~4~

-Exploratory Drilling CH~4~

-Equipment Leaks CH~4~

-Maintenance Activities CH~4~, CO~2~

-Turnaround Activities CH~4~, CO~2~

-Emergency/Upset Conditions CH~4~, CO~2~

Emissions from vents and stacks:

-Glycol Dehydrators CH~4~, CO~2~

-Glycol Pumps CH~4~

-Acid Gas Removal CH~4~

-Sour Gas Processing CO~2~

-Catalytic Cracking Regenerators CH~4~, CO~2~

-Refinery Hydrogen Plants CO~2~

-Cokers CO~2~

-Catalyst Regeneration CO~2~

-Cold Process Vents CH~4~, CO~2~

-Gas Driven Pneumatic Devices CH~4~, CO~2~

-Gas Driven Chemical Injection Pumps CH~4~, CO~2~

The most accurate estimates of emissions will typically come from direct
measurements of actual emissions or all of the factors necessary for
mass balance calculations. This is most plausible for emissions from
point sources, including process vents and emission stacks, although
fugitive emissions can also be estimated by taking direct measurements
of equipment leaks and losses. Direct measurements will often be used in
conjunction with empirical correlation equations and other activity data
to derive an emission estimate. In general, estimates based on direct,
site-specific measurements will be assigned a rating of "A," provided
measurement equipment is calibrated at least twice annually. Reporters
should be able to document all of the methods, data and techniques used
for each emission estimate.

Many emissions, particularly for the oil industry, can be accurately
estimated using a mass balance approach. The *Revised 1996 IPCC
Guidelines for National Greenhouse Gas Inventories: Reference Manual*
provides an overview, guidance, and methods for performing mass-balance
estimates of methane emissions from oil production, crude oil
transportation and refining, and from losses during oil exploration and
drilling. In general, emission estimates based on mass balance
approaches that use measured activity and composition data are the most
accurate. But reasonably accurate estimates may also be made by
combining measured activity data and emission factors that are publicly
documented and widely reviewed and adopted by a public agency, a
standards-setting organization or an industry group. For example IPCC's
*Good Practice Guidance* provides a table of default emissions factors
for fugitive emissions from oil and gas operations based on North
American data.[^112] Reporters can also find default emissions factors
from a variety of other well-documents sources, including the EPA's
*AP-42*, API's *Compendium of Greenhouse Gas Estimation Methodologies,*
and the EPA's *Emission Inventory Improvement Program*. Methods that
combine measured activity data and such widely accepted emission
factors,will be assigned a rating of "B." Again, reporters should be
able to document all of the methods, data and techniques used for each
emission estimate.

In the absence of other data, reporters can estimate emissions using
other default emissions factors based on general activity data. Those
estimates tend to have very high levels of uncertainty, and should only
be used as a last option. In general, emission estimates based on other
default emissions factors will be assigned a rating of "C" and emission
estimates that are derived from estimated activity data and default
emission factors will be assigned a rating of "D".

Ratings of methods for estimating emissions from natural gas and oil
operations are summarized in Table 1.E.29. In situations where reporters
must use multiple authorities to estimate emissions from a particular
source (e.g., where the method for calculating emissions from a single
source is a multi-stepped process, and reporters use values or methods
from more than one authority to complete the process), estimates will be
assigned the rating of the lowest rated method used.

###### Table 1.E.29. Rating of Estimation Methods for Carbon Dioxide and Methane Emissions from Oil and Natural Gas Industries

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Direct, site-specific measurements of emissions or all mass      A
  balance factors                                                  

  Mass-balance approach, using measured activity data and emission B
  factors that are publicly documented and widely reviewed and     
  adopted by a public agency, a standards-setting organization or  
  an industry group                                                

  Mass-balance approach, using measured activity data and other    C
  emission factors                                                 

  Mass balance approach using estimated activity data and default  D
  emissions factors                                                
  ---------------------------------------------------------------- ------------

##### 1.E.4.3 Waste Handling

Many industries generate considerable quantities of waste or byproduct
during the course of their process activities. Waste is also generated
by a number of non-industrial sources, including human wastes collected
in sewage and drainage systems. Depending on their composition and how
they are treated or stored, these waste streams can release significant
quantities of greenhouse gas emissions, usually as a result of the
aerobic and anaerobic decomposition of the organic matter in the waste.
In some cases, these emissions will account for an industry's primary
source of greenhouse gas emissions. Given the wide range of potential
emissions arising from the variety of wastes, and treatment and storage
practices, it is important for reporters to accurately characterize the
nature and fate of the waste for which they are estimating emissions.

In this guidance, waste will be classified as solid or liquid. Solid
waste can be collected in landfills, recycled, composted or combusted.
While a large percentage of the solid waste that is generated by
industries may be sold or transferred to off-site, centralized
landfills, some industrial facilities may store waste in on-site
landfills. Liquid wastes, referred to herein as "wastewater," are
generally treated to remove undesirable or potentially harmful contents,
including soluble organic matter, suspended solids, pathogenic
organisms, and chemical contaminants. Once treated, wastewater may be
further processed, or discharged into nearby sewage systems or bodies of
water. Reporters should use this guidance to estimate only those
emissions that are generated from the wastes that they handle or treat
directly. This section provides specific guidance on estimating
emissions from landfills and from domestic and industrial wastewater.

Carbon dioxide and methane are the primary greenhouse gases released
during the biological decomposition of the organic content of waste. The
relative availability of oxygen is a critical determinant of the
composition of the evolved biogas. When oxygen is abundant, aerobic
bacteria perform the majority of the decomposition, breaking organic
matter into simple carbohydrates, and eventually into hydrogen gas,
carbon dioxide and carboxylic acids. When free oxygen is not available,
is in low concentrations, or has been consumed by the action of aerobic
bacteria, anaerobic (or methanogenic) bacteria decompose organic
material and produce methane.

While the complete mechanisms are still not understood, other factors
affecting the composition and rate at which biogas is emitted include
the temperature, composition (e.g., relative ratio of lipids,
carbohydrates, inert substances, organic and inorganic contents),
chemical characteristics (e.g., acidity, salinity, alkalinity), and
physical characteristics (e.g., size, surface area, interstitial space)
of the waste materials. The accuracy of emission estimates is therefore
generally correlated to the degree to which the waste material is
characterized. Specific guidance is provided to help reporters account
for these variables associated with their wastes.

While waste management generates most greenhouse gases in some quantity,
the most significant of these is methane.[^113] Landfills are the single
largest source of anthropogenic methane emissions in the United States,
accounting for nearly 26 percent of methane emissions in 2002.[^114] In
some cases methane emissions are collected and subsequently flared or
combusted to produce heat or to generate electricity. In both practices,
the methane is converted to carbon dioxide via combustion. Methane and
carbon dioxide emissions are accounted for in the following ways:

-   Carbon dioxide emissions from the aerobic bacterial decomposition of
    wastes are considered biogenic and therefore do not count as
    reportable greenhouse gas emissions under the 1605(b) Program.

-   Methane emissions from the anaerobic bacterial decomposition of
    wastes are considered anthropogenic and should be included in
    estimates of greenhouse gas emissions.

-   Carbon dioxide emissions from flaring methane derived from wastes
    are considered biogenic and need not be reported since they will
    result in net-zero carbon dioxide emissions.

-   Carbon dioxide emissions from combusting methane in landfill gas for
    energy purposes (e.g., heat, electricity generation) are considered
    biogenic and should not be included in estimates of greenhouse gas
    emissions. Electricity and heat generated from waste-derived methane
    may, under the circumstances specified by the General Guidelines,
    result in an emission reduction or "avoided emissions" by displacing
    electricity or heat generated through fossil fuel combustion, see
    Chapter 2, Emission Reductions.

-   Treatment of emissions from the combustion of waste matter for
    energy is dependent on the nature of the waste matter. Carbon
    dioxide emissions from the combustion of organic waste matter are
    considered biogenic, and therefore are not to be included in
    estimates of greenhouse gas emissions. Carbon dioxide emissions from
    the combustion of inorganic, or petroleum-derived waste matter,
    however, are considered anthropogenic and should be estimated using
    the methods described in Part C, "Stationary Combustion."

In some cases, an industrial facility will operate more than one waste
management or handling facility. In these instances, emissions should be
calculated separately for individual facilities. Total emissions should
be summed after emissions from individual facilities are estimated.

The following subsections discuss emissions from wastewater treatment
and landfills, respectively.

**1.E.4.3.1 Methane Emissions from Domestic and Industrial Wastewater
Handling**

Wastewater is generated by both industrial and domestic sources.
Domestic wastewater is composed primarily of human wastes, sewage and
urban run-off, and is typically treated in centralized municipal
treatment facilities. Many industries produce wastewater streams of
varying content, which are either disposed of directly (e.g., fed into a
municipal treatment facility) or treated on-site. This section provides
guidance on estimating emissions from both domestic and industrial
wastewater treatment practices.

Wastewater streams most likely to produce significant methane emissions
are those that are rich in organic matter, including domestic wastewater
as well as wastewater streams from the pulp and paper manufacturing
industries, meat and poultry packing industries, and vegetable, fruit
and juice processing industries. According to the U.S. EPA, domestic
wastewater treatment generated 19.8 million metric tons carbon dioxide
equivalent of methane emissions in 2003, while wastewater from the pulp
and paper, meat and poultry packing, and fruit and juice industries
emitted 16.9 million metric tons carbon dioxide equivalent in the same
year.[^115] Wastewater can also be generated during the manufacture of
textiles, petrochemical products, fertilizers, iron and steel, and
organic chemicals.

Due to the variability of the composition of wastewater streams,
emission rates are specific to source and industry. Estimates based on
measured wastewater stream composition data will be assigned a rating of
"A." Where direct measurement of the wastewater stream composition is
not practical, reporters can use default source or industry-specific
emissions factors. Estimates based on default emissions factors will be
assigned a rating of "B."

The level and number of treatment operations to which wastewater is
subjected are highly variable. Some industries perform minimal treatment
before discharging into sewage systems or other treatment plants. Others
will subject their wastewater to much more extensive treatment,
collecting the resulting biomass or emissions for energy generation,
resource recovery or emission reductions. There are three general levels
of treatment:

-   Primary treatment **--** suspended solids are removed, usually by
    filtration and/or settling.

-   Secondary treatment **--** organic content is further reduced
    through the action of microbial decomposition (aerobic or
    anaerobic).

-   Tertiary treatment **--** inorganic compounds and remaining
    pathogens are removed through a variety of processes/applications,
    including chemical disinfection, advanced filtration, ion exchange,
    and carbon adsorption systems.

The solid components removed during primary and secondary treatment are
referred to as sludge. In primary treatment, sludge consists of the
materials that are physically filtered out of the wastewater. The sludge
produced during secondary treatment is the result of the increase in
biomass of the microbial agents responsible for the decomposition of the
organic matter. Sludge also generates emissions, and is also typically
subject to treatment before it can be safely disposed or used in a given
application.

Due to the variety of treatment methods, and the resulting multitude of
treatment combinations possible, reporters should estimate emissions
from each of the wastewater treatment facilities (also referred to as
"handling" facilities) separately. Emissions will vary from facility to
facility based on the treatment type, content of the wastewater, and a
number of other factors. The principal determinant of methane production
potential for a given wastewater stream, however, is its quantity of
degradable organic matter, referred to as degradable organic content or
DOC.

DOC is typically expressed in terms of chemical or biochemical oxygen
content (COD or BOD, respectively). BOD represents the total amount of
oxygen that would be consumed by aerobic bacteria in the process of
decomposing all of the organic matter contained in wastewater.
Similarly, COD is a measure of the total amount of oxygen needed to
completely oxidize the organic and oxidizable inorganic matter content
of a water sample under specified conditions. Both measurements are
usually given in units of mass over volume (e.g., lbs COD/square foot
water).

In most cases, industrial reporters should measure DOC using COD,
whereas domestic treatment facilities should estimate DOC by measuring
BOD.[^116] There are a number of testing systems available for reporters
to measure the COD of their wastewater.[^117] Reporters should follow
the EPA's quality control acceptance criteria for COD
measurements.[^118] If direct measurements are not feasible, the IPCC
provides default COD values for industrial wastewater by region and by
industry.

The *Revised 1996 IPCC Guidelines for National Greenhouse Gas Estimation
Inventories* provides a three-step, emissions factor-based method for
estimating emissions from industrial and domestic wastewater and
sludge.[^119] The three steps are:

1.  Estimate total DOC of all the wastewater/sludge treated at each
    handling facility.

2.  Estimate emissions factors for each wastewater/sludge treatment
    process.

3.  Multiply emissions factors by the DOC.

While the methods for these three steps are analogous for domestic and
industrial wastewater, the method for estimating DOC differs for each.
In the methods outlined below, the calculations for estimating DOC in
industrial and domestic wastewater streams are presented separately. As
the subsequent two steps are the same for both sources, they are
presented together. The methods below will yield methane emission
estimates. Sewage and other streams that contain large amounts of high
protein waste will also generate emissions of nitrous oxide. A method
for estimating nitrous oxide emissions is provided immediately following
the one below on methane emissions.

In addition to the IPCC method for estimating methane emissions from
industrial wastewater treatment presented below, reporters may use the
International Council of Forest and Paper Associations (ICFPA) method
developed for the pulp and paper industry by the National Council for
Air and Stream Improvement, Inc.[^120]

***Step 1. Domestic Wastewater and Sludge: Estimate Total Organic
Content***

The total DOC content of a given quantity of wastewater in a given
period of time (total organic content, TOC), measured in kg BOD, can be
estimated by two methods. The preferable method is to directly measure
the BOD content of the wastewater/sludge treated, and extrapolate to the
entire volume of wastewater/sludge treated. This value must then be
corrected for the portion of DOC that is removed as sludge.

**Domestic Wastewater**

**TOC~W~ (kg BOD / year) = W \* DOC~W~ \* (1 -- DS)**

**Where:**

**TOC~W~ = total organic content of domestic wastewater,**

> **measured in kg BOD / year**

**W = quantity of domestic wastewater treated per year,**

> **measured in cubic meters**

**DOC~W~ = degradable organic component of domestic**

> **wastewater, measured in kg BOD / cubic meters**

**DS = quantity of degradable organic content removed from**

> **domestic wastewater as sludge, as a percentage**

In the absence of direct BOD measurements, reporters can estimate total
DOC by multiplying the total population for which they are treating
wastewater by an estimate of per capita DOC production:

**TOC~W~ (kg BOD / year) = P \* DCP \* (1 -- DS)**

**Where:**

**TOC~W~ = total organic content of domestic wastewater,**

> **measured in kg BOD / year**

**P = total population served by a single treatment facility, in**

> **thousands**

**DCP = degradable organic component production per**

> **thousand persons per year, measured in kg BOD**

**DS = percentage of degradable organic content removed from**

> **domestic wastewater as sludge**

If region-specific DOC production data are not available, reporters can
use the national average value of 23.7 thousand metric tons BOD produced
per person per year.[^121]

**Domestic Sludge**

**TOC~S~ (kg BOD / year) = W \* DOC~W~ \* DS**

**Where:**

**TOC~S~ = total organic content of domestic sludge,**

> **measured in kg BOD / year**

**W = quantity of domestic wastewater treated per year,**

> **measured in cubic meters**

**DOC~W~ = degradable organic component of domestic**

> **wastewater, measured in kg BOD / cubic meter**

**DS = quantity of degradable organic content removed**

> **from domestic wastewater as sludge, as a**
>
> **percentage**

In the absence of direct BOD measurements, reporters can estimate total
DOC by multiplying the total population for which they are treating
wastewater by an estimate of per capita DOC production:

**TOC~S~ (kg COD / year) = P \* DCP \* DS**

**Where:**

**TOC~S~ = total organic content of domestic sludge,**

> **measured in BOD / year**

**P = total population served by a single treatment facility, in**

> **thousands**

**DCP = degradable organic component production per**

> **thousand persons per year, measured in kg COD**

**DS = quantity of degradable organic content removed from**

> **domestic wastewater as sludge, as a percentage**

***Step 2. Industrial Wastewater and Sludge: Estimate Total Organic
Content***

The total quantity of organic matter in industrial wastewater and sludge
can be estimated by multiplying total quantity of wastewater treated and
the DOC of the wastewater and sludge.

Total organic content can be estimated using the following formulas:

**Industrial Wastewater**

**TOC~i~ (kg COD / year) = W~i~ \* O~i~ \* DOC~i~ \* (1 -- DS ~i~)**

**Where:**

**TOC~i~ = total organic content of industrial wastewater type *i*,**

> **measured in kg COD / year**

**W~i~ = quantity of wastewater type *i* produced per metric ton**

> **of industrial product, measured in cubic meters**

**O~i~ = annual output of industrial product, in tons**

**DOC~i~ = degradable organic component of wastewater type *i*,**

> **measured in kg COD / cubic meter**

**DS~i~ = quantity of degradable organic content removed**

> **from wastewater type *i* as sludge, as a percentage**

**Industrial Sludge**

**TOC~j~ (kg COD / year) = WS~j~ \* O \* DOC~j~ \* DS~j~**

**Where:**

**TOC~j~ = total organic content of industrial sludge type *j*,**

> **measured in kg COD / year**

**WS~j~ = quantity of sludge type *j* produced per metric ton of**

> **industrial product, measured in cubic meters**

**O = annual output of industrial product**

**DOC~j~ = degradable organic component of wastewater type *j*,**

> **measured in kg COD / cubic meter**

**DS~j~ = quantity of degradable organic content removed**

> **from wastewater as sludge, as a percentage**

Where direct measurements are not feasible, reporters can use the
default COD values provided in Table 1.E.30.

###### Table 1.E.30. Default COD Values for Various Types of Industrial Wastewater

+----------------------+-----------------------+-----------------------+
| **Industry Type**    | **Wastewater          | **COD Value**         |
|                      | Produced**            |                       |
|                      |                       | **(kg COD / m^3^      |
|                      | **(m^3^ / metric ton  | wastewater)**         |
|                      | product)**            |                       |
+======================+=======================+=======================+
| Coffee               | \-                    | 8.5                   |
+----------------------+-----------------------+-----------------------+
| Potatoes             | \-                    | 3.0                   |
+----------------------+-----------------------+-----------------------+
| Vegetable Oil        | 1.6                   | 0.3                   |
+----------------------+-----------------------+-----------------------+
| Dairy Products       | 2.8                   | \-                    |
+----------------------+-----------------------+-----------------------+
| Cannery              | 2.6                   | \-                    |
+----------------------+-----------------------+-----------------------+
| Potato Starch        | \-                    | 8.0                   |
+----------------------+-----------------------+-----------------------+
| Wheat Starch         | \-                    | 22                    |
+----------------------+-----------------------+-----------------------+
| Petroleum Products   | \-                    | 0.4                   |
+----------------------+-----------------------+-----------------------+
| Textile mills        | \-                    | 1.0                   |
+----------------------+-----------------------+-----------------------+
| Leather tanning      | \-                    | 5.8                   |
+----------------------+-----------------------+-----------------------+
| Pulp and Paper\*     | 72\*\*                | 0.4\*\*\*             |
+----------------------+-----------------------+-----------------------+
| Meat and Poultry\*   | 13                    | 4.1                   |
+----------------------+-----------------------+-----------------------+
| Fruits, Vegetables,  | 5.6                   | 5.0                   |
| Juices\*             |                       |                       |
+----------------------+-----------------------+-----------------------+
| Source:              |                       |                       |
| Intergovernmental    |                       |                       |
| Panel on Climate     |                       |                       |
| Change, *Revised     |                       |                       |
| 1996 IPCC Guidelines |                       |                       |
| for National         |                       |                       |
| Greenhouse Gas       |                       |                       |
| Inventories:         |                       |                       |
| Reference Manual*    |                       |                       |
| (1997).              |                       |                       |
|                      |                       |                       |
| \* U.S.              |                       |                       |
| Environmental        |                       |                       |
| Protection Agency,   |                       |                       |
| *Inventory of U.S.   |                       |                       |
| Greenhouse Gas       |                       |                       |
| Emissions and Sinks: |                       |                       |
| 1990-2001* (2003).   |                       |                       |
|                      |                       |                       |
| \*\*National Council |                       |                       |
| for Air and Stream   |                       |                       |
| Improvement, Inc.    |                       |                       |
| (NCASI). 2003. Pulp  |                       |                       |
| Mill Process         |                       |                       |
| Closure: A Review of |                       |                       |
| Global Technology    |                       |                       |
| Developments and     |                       |                       |
| Mill Experiences in  |                       |                       |
| the 1990s. Technical |                       |                       |
| Bulletin No. 0860.   |                       |                       |
| Research Triangle    |                       |                       |
| Park, NC: National   |                       |                       |
| Council for Air and  |                       |                       |
| Stream Improvement,  |                       |                       |
| Inc. Website:        |                       |                       |
| <http://www.nca      |                       |                       |
| si.org//Publications |                       |                       |
| /Detail.aspx?id=84>. |                       |                       |
|                      |                       |                       |
| \*\*\*BOD value      |                       |                       |
+----------------------+-----------------------+-----------------------+

***Step 3. Domestic and Industrial Wastewater and Sludge: Calculate
Emissions Factors***

Emissions factors for different wastewater and sludge types can be
calculated given the maximum methane-producing capacity and the methane
conversion factor (MCF) for each type of wastewater or sludge handled,
in conjunction with knowledge of the treatment type to which each
wastewater or sludge stream is subjected. Methane-producing capacity
depends on the composition and degradability of the wastewater or
sludge. In the absence of a measured value, a default value of 0.25 kg
methane/kg COD[^122] can be used. Similarly, the MCF varies from zero in
completely aerobic systems to one in completely anaerobic systems.

Where sludge is incinerated, burned for energy, or landfilled, its
emissions should be estimated separately, using the appropriate methods
(found in Part C, "Stationary Combustion" and below in subsection
1.E.4.3.3, Landfill Methane, respectively). In these cases, the sludge
should be assigned an MCF of zero in order to avoid double counting.
Otherwise, an MCF value representative of the system used to dispose of
the sludge should be used.

Methane emissions factors for individual wastewater and sludge handling
facilities can be calculated using the following formulas:

**Wastewater**

**EF~i~ (kg CH~4~ / kg DOC) = B~i~ \* MCF~x~**

**Where:**

**EF*~i~* = methane emissions factor for wastewater type *i*,**

> **measured in kg CH~4~ / kg DOC**

**B*~i~* = maximum methane producing capacity of**

> **wastewater type *i*, measured in kg CH~4~ / kg DOC**

**MCF*~x~* = methane conversion factor of wastewater treatment**

> **system *x***

**Sludge**

**EF~i~ (kg CH~4~ / kg DOC) = B~i~ \* MCF~y~**

**Where:**

**EF*~j~* = methane emissions factor for sludge type *j*, measured**

> **in kg CH~4~ / kg DOC**

**B*~j~* = maximum methane producing capacity of sludge**

> **type *j*, measured in kg CH~4~ / kg DOC**

**MCF*~y~* = methane conversion factor of sludge treatment**

> **method *y***

In the absence of site-specific data, reporters can use default methane
conversion factor values of zero for aerobic systems and one for
anaerobic systems, respectively, and default maximum methane producing
capacity values of 0.25 kg CH~4~/kg COD and 0.6 kg CH~4~/kg BOD for
estimates of DOC measured in COD or BOD, respectively.[^123]

***Step 4. Domestic and Industrial Wastewater and Sludge: Estimate Total
Methane Emissions for Individual Facilities***

In estimating total methane emissions from individual wastewater or
sludge-handling facilities, methane emissions are equal to the
associated emissions factor multiplied by the quantity of wastewater or
sludge produced:

**Wastewater**

**MW~i~ (kg CH~4~) = TOC~i~ \* EF~i~**

**Where:**

**MW~j~ = methane emissions from wastewater type *i*, measured in kg**

> **methane**

**TOC~j~ = total organic content of wastewater type *i*,**

> **measured in kg COD or BOD / year**

**EF~i~ = methane emissions factor for wastewater type *i*,**

> **measured in kg CH~4~ / kg TOC**

**Sludge**

**MS~i~ (kg CH~4~) = TOC~j~ \* EF~j~**

**Where:**

**MW~j~ = methane emissions from sludge type *j*, measured in kg**

> **methane**

**TOC~j~ = total organic content of sludge type *j*,**

> **measured in kg COD / year**

**EF~j~ = methane emissions factor for sludge type *j*,**

> **measured in kg CH~4~ / kg TOC**

***Step 5: Total Emissions***

Sum the emissions from all wastewater and sludge-handling facilities for
total methane emissions from wastewater production.

Ratings of methods for estimating emissions from wastewater handling are
summarized in Table 1.E.31.

###### Table 1.E.31. Rating of Estimation Methods for Methane Emissions from Wastewater and Sludge Handling

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Emissions factors derived from measured wastewater stream        A
  composition data[^124]                                           

  Default emissions factors and general activity data[^125]        B
  ---------------------------------------------------------------- ------------

**1.E.4.3.2 Nitrous Oxide Emissions from Domestic Wastewater**

Domestic wastewater streams will also generate nitrous oxide emissions.
Nitrous oxide is released as a byproduct of two processes: nitrification
and denitrification. Nitrification is an aerobic process through which
nitrogen, present in human wastes in the form of urea, ammonia and
protein, is converted ultimately to nitrate. Denitrification, in
contrast, is an anaerobic process through which nitrate is biologically
converted to gaseous nitrogen. Most nitrous oxide emissions occur during
either wastewater treatment practices themselves, or following such
treatment, when the remaining effluent is discharged into nearby aquatic
environments.

Reporters can estimate nitrous oxide emissions from discharged effluent
with the following equation:[^126]

**N~2~O~effluent~ = Frac~effluent~ \* P \* Protein \* Frac~protein~ \*
EF**

**Where:**

**N~2~O~effluent~ = nitrous oxide emissions from effluent disposed of in
aquatic**

> **environments**

**Frac~effluent~ = fraction of wastewater that is disposed of in**

> **waterways as effluent, as a percentage**

**P = total population served by treatment facility**

**Protein = annual per capita protein intake, measured in**

> **kg / person / year**

**Frac~protein~ = fraction of nitrogen in protein**

**EF = nitrous oxide emissions factor, as measured in**

> **kg N~2~O-N / kg sewage-N produced.**

Estimates based on direct measurements of emissions will be assigned a
rating of "A." Estimates based on this equation in conjunction with
measured, site-specific data will be rated "B." In the absence of
site-specific data, reporters can use the IPCC default values provided
in Table 1.E.32. Estimates based on these data will be rated "C."

###### Table 1.E.32. Default Values for Estimating Nitrous Oxide Emissions from Disposed Effluent

+-----------------------------------+----------------------------------+
| Annual per capita protein intake  | 41.6 ^\*^                        |
+-----------------------------------+----------------------------------+
| Fraction of nitrogen in protein   | 0.16 kg N / kg protein           |
+-----------------------------------+----------------------------------+
| Nitrous oxide emissions factor    | 0.01 kg N~2~O /kg sewage N       |
|                                   | produced                         |
+-----------------------------------+----------------------------------+
| Source**:** Intergovernmental     |                                  |
| Panel on Climate Change, *Revised |                                  |
| 1996 IPCC Guidelines for National |                                  |
| Greenhouse Gas Inventories:       |                                  |
| Reference Manual* (1997).         |                                  |
|                                   |                                  |
| ^\*^ U.S. Environmental           |                                  |
| Protection Agency, *Inventory of  |                                  |
| U.S. Greenhouse Gas Emissions and |                                  |
| Sinks: 1990-2001* (2003).         |                                  |
+-----------------------------------+----------------------------------+

Ratings of methods for estimating emissions from wastewater handling are
summarized in Table 1.E.33.

###### Table 1.E.33. Rating of Estimation Methods for Nitrous Oxide Emissions from Disposed Effluent

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Direct measurement                                               A

  IPCC method using measured, site-specific effluent data          B

  IPCC method using default values                                 C
  ---------------------------------------------------------------- ------------

**1.E.4.3.3 Landfill Methane**

Methane is released from landfills through the anaerobic decomposition
of organic wastes such as paper, food, and yard waste, and accounts for
30 to 60 percent by volume of all gases emitted from landfills.[^127]
The balance of gases includes primarily carbon dioxide and other minor
constituents such as nitrogen, volatile organic compounds, and water
vapor. The capture and combustion of landfill gas is a common practice
used to mitigate methane and other air pollutants in the gas.[^128]

The amount and rate at which methane is generated and emitted from a
landfill is a function of several factors, including but not limited to,
the composition of waste, PH levels in the landfill, moisture content of
the waste, the landfill temperature, and the amount of oxidation that
occurs as the methane passes through the landfill cover material.
Additionally, methane is not emitted immediately after it is placed in a
landfill. The time lag before anaerobic decomposition of organic matter
begins and the pace of that decomposition are dependent on the above
factors.

Reporters may choose from two basic methodological approaches for
estimating methane emissions from landfills. The first, the First Order
Decay (FOD) model, captures the temporal profile of decomposition, while
the latter, the EMCON Methane Generation Model, simply captures a
snapshot of total methane emissions from any given volume of waste
landfilled.

The First Order Decay model captures the temporal profile of
decomposition and requires multiple-year data on:

-   The amount of waste landfilled;

-   The degradable organic portion of the waste;

-   The fraction of the degradable organic portion that actually
    decomposes;

-   The fraction of methane in landfill gas;

-   The methane generation rate constant (representing the half-life of
    the degradable organic portion of the waste);

-   The portion of methane generated that is oxidized in cover soil; and

-   The amount of methane recovered from the landfill.

The FOD model can be represented by the equation:

**CH~4~ Generated in year t = Σ~x~ \[(A \* k \* MSW~t\ (x)~ \* MSW~f(x)~
\* L~0(x)~) \* e^-k(t-x)^\]**

**For x = initial year to t**

**Where:**

**t = year of inventory**

**x = years for which input data should be added**

**A = (1- e^-k^)/k; normalization factor which corrects the summation**

**k = methane generation rate constant (1/number of years)**

**MSW~t(x)~ = total municipal solid waste generated in year x**

**MSW~f(x)~ = fraction of municipal solid waste disposed at landfills in
year x**

**L~0(x)~ = methane generation potential \[MCF~(x)~ \* DOC~(x)~ \*
DOC~(f)~**

> **\* F \* 16/12**

**e = Euler\'s constant equal to the natural logarithm base *e*,**

**approximately 2.71828**

**MCF~(x)~ = methane correction factor for year x (fraction)**

**DOC~(x)~ = degradable organic carbon in year x (fraction)**

**DOC~(f)~ = Fraction of DOC dissimilated**

**F = Fraction by volume of CH~4~ in landfill gas**

**16/12 = Conversion of carbon to CH~4~**

The degradable organic carbon content of the waste can be calculated by
determining the composition of waste, using data which include:

-   The fraction of waste that is paper and textiles;

-   The fraction that is yard waste;

-   The fraction that is food waste; and

-   The fraction that is wood or straw.

For the detailed requirements of this method, reporters should refer to
the waste sections in both the *Revised 1996 IPCC Guidelines for
National Greenhouse Gas Inventories: Reference Manual*[^129] and the
*IPCC Good Practices Guidance and Uncertainty Management in National
Greenhouse Gas Inventories*.[^130] In order to use this model, detailed
knowledge of the waste characteristics and landfill parameters listed
above is required. If those data are available and used, this method is
assigned a rating of "A."

There are a number of publicly available tools for implementing the
First Order Decay model based on a combination of critical default
factors and key landfill-specific parameters. They include LandGEM,
available at no cost from the U.S. Environmental Protection Agency and
downloadable from the Internet at
[www.epa.gov/ttn/catc/products.html#software](http://www.epa.gov/ttn/catc/products.html#software).
The LandGEM model uses a first-order decomposition rate equation to
estimate annual gas generation over any time period specified by the
user. The following list of information is required for the LandGEM
model to estimate gas generation from a landfill:

-   The design capacity of the landfill;

```{=html}
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```
-   The amount of refuse landfilled each year (waste acceptance rate);

-   The opening and closing years of the landfill;

-   The methane generation rate (k) (default values are available);

-   The methane generation potential (L~o~) (default values are
    available); and

-   The concentration of methane, (default values are available).

As noted above, the LandGEM model can be run using either user-defined
data or program-provided default values for k, L~o~ and methane
concentration. If site-specific data are not available, LandGEM's
"AP-42" default values may be used.

If site-specific data are used for all inputs required by LandGEM,
emissions estimates are assigned a rating of "A." If default values are
used, emissions estimates using LandGEM are assigned a rating of "B."

Alternatively, reporters may wish to use the default parameters from the
EMCON Methane Generation Model in conjunction with estimates of volume
of waste landfilled each year as a simplified method of capturing the
temporal profile of waste decomposition in their landfill.[^131] This
model provides default factors for waste composition, methane yield,
time lag to onset of waste decomposition, and a time constant reflecting
the total time required for the methane yield to be realized.

The EIA has developed a parameterization of the EMCON model that is used
to develop estimates of national methane emissions. This method may be
applied to individual landfills by inserting the parameters listed in
Table 1.E.34 and volumes of waste landfilled on an annual basis into
EIA's spreadsheet application. Reporters should take an average of the
high-yield and low-yield scenario for each of the three different waste
categories---readily decomposable, moderately decomposable, and slowly
decomposable waste---and sum these emissions on an annual basis.

If site-specific data are used for all inputs required by EMCON,
emissions estimates are assigned a rating of "A." If default values are
used, emissions estimates using EMCON are assigned a rating of "B.

###### Table 1.E.34. EMCON Methane Generation Model Parameters for Calculating Methane Emissions

+---------------------------+-----------+---------+---------+---------+
| **Waste Category**        | **Dec     | **      | **Lag   | **Time  |
|                           | omposable | Methane | Time    | C       |
|                           | Portion   | Yield** | (Y      | onstant |
|                           | (% by Dry |         | ears)** | (Y      |
|                           | Weight)** | *       |         | ears)** |
|                           |           | *(Cubic |         |         |
|                           |           | Feet    |         |         |
|                           |           | per     |         |         |
|                           |           | P       |         |         |
|                           |           | ound)** |         |         |
+===========================+===========+=========+=========+=========+
| **High Yield**            |           |         |         |         |
+---------------------------+-----------+---------+---------+---------+
| Readily Decomposable      | 4         | 4.5     | 0.2     | 3       |
+---------------------------+-----------+---------+---------+---------+
| Moderately Decomposable   | 45        | 3.6     | 1.5     | 10      |
+---------------------------+-----------+---------+---------+---------+
| Slowly Decomposable       | 5.2       | 0.5     | 5       | 20      |
+---------------------------+-----------+---------+---------+---------+
| **Low Yield**             |           |         |         |         |
+---------------------------+-----------+---------+---------+---------+
| Readily Decomposable      | 4         | 2.8     | 0.3     | 4       |
+---------------------------+-----------+---------+---------+---------+
| Moderately Decomposable   | 45        | 2       | 2       | 20      |
+---------------------------+-----------+---------+---------+---------+
| Slowly Decomposable       | 5.2       | 0.3     | 5       | 40      |
+---------------------------+-----------+---------+---------+---------+
| Source**:** Energy        |           |         |         |         |
| Information               |           |         |         |         |
| Administration,           |           |         |         |         |
| *Documentation for        |           |         |         |         |
| Emissions of Greenhouse   |           |         |         |         |
| Gases in the United       |           |         |         |         |
| States 2003* (Washington, |           |         |         |         |
| DC May 2005),             |           |         |         |         |
| [www.eia.doe.go           |           |         |         |         |
| v/oiaf/1605/ggrpt/documen |           |         |         |         |
| tation/pdf/0638(2003).pdf |           |         |         |         |
| ](http://www.eia.doe.gov/ |           |         |         |         |
| oiaf/1605/ggrpt/documenta |           |         |         |         |
| tion/pdf/0638(2003).pdf). |           |         |         |         |
+---------------------------+-----------+---------+---------+---------+

When the First Order Decay Model or its derivatives are used, an
oxidation rate of 10 percent should be used to reflect the oxidation of
some of the methane produced while it passes through the landfill cover
material. When using the EMCON parameters, simply reduce the total
estimate of emissions for any given year by 10 percent to reflect
oxidation. If the landfill has a recovery system in place, the amount
recovered should be deducted from total estimated emissions before the
emissions are reduced by 10 percent to account for oxidation.[^132] This
is represented by the equation:

**CH~4~ emissions = (CH~4~ generated in year t -- CH~4~ Recovery in year
t) \* (1 -- oxidation rate)**

The First Order Decay Model and its derivative tools require a
time-series of data on amounts of waste landfilled for multiple years
prior to the inventory reporting year. If data on landfilled waste are
only available for a single year or a limited number of years, the
theoretical gas yield methodology may also be used. This mass balance
approach assumes that all the potential methane in a given amount of
waste is released from the landfill in the same year the waste is
landfilled. This method does not precisely portray what happens in a
landfill over time, but provides a reasonable estimate of the total
amount of methane released over time from a given amount of waste.
Reporters should use caution when using the mass balance approach if the
waste stream is changing or there is methane recovery. This approach is
found under the *Revised 1996 IPCC Guidelines* and is given a rating of
"C." To estimate a single year's methane emissions from landfilled waste
use the following formula:

**CH~4~ Emissions = \[(Waste landfilled \* DOC \* Dissimilated DOC \*
0.5 \* 16/12)\
(CH~4~ recovered)\] \* (1 -- oxidation rate)**

**Where:**

> **DOC = Fraction of Degradable Organic Carbon Content in waste (Gg
> C/Gg waste).**

**Dissimilated DOC = Fraction of DOC dissimilated (Gg C/Gg waste)**

> **CH~4~ recovered = Methane captured or otherwise prevented from being
> emitted**

**16/12 = Molecular weight ration of methane to carbon**

**Oxidation rate = Rate of oxidation (%)**

**Waste landfilled = Waste landfilled (Gg)**

However, if data on the degradable organic content, the fraction of DOC
dissimilated, or the oxidation factor are unavailable, then reporters
may use the following IPCC default values:[^133]

**CH~4~ Emissions = \[Waste landfilled \* 0.21(DOC) \* 0.77(Dissimilated
DOC) \* 0.5\
\* 16/12\] -- (CH~4~ recovered) \* (1 -- oxidation rate)**

An oxidation rate of 10 percent may be assumed.

Emissions estimates using the mass-balance method based on the default
values will be assigned a rating of "D."

Ratings of methods for estimating emissions from landfills are
summarized in Table 1.E.35.

###### Table 1.E.35. Rating of Estimation Methods for Methane Emissions from Landfilling

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  IPCC First Order Decay model using site-specific waste and       A
  landfill parameters                                              

  Publicly available models, including LandGem and EMCON, that     A
  rely on user-defined data elements                               

  Publicly available models, including LandGem and EMCON, that     B
  rely on default parameters                                       

  Mass balance using single (or limited number of) year(s),        C
  site-specific DOC data                                           

  Mass balance, default DOC values                                 D
  ---------------------------------------------------------------- ------------

##### 

##### 1.E.4.4 High Global Warming Potential Gases

Many industries emit a host of gases known as high global warming
potential (GWP) gases. Although typically emitted in relatively small
quantities, these gases are of concern because some of these gases have
over 10,000 times the global warming potential[^134] of carbon dioxide
on a pound-per-pound basis.

The use and release of these gases varies widely by industry and by
process. High GWP gases can be used as cover gases (as in magnesium
production), as substitutes for ozone-depleting propellants (as in
aerosols), or as cleaning agents (as in semiconductor manufacture). The
industrial uses of high GWP gases discussed in this guidance are
indicated in Table 1.E.36.

###### Table 1.E.36. Industrial Processes Associated with Emissions of High GWP Gases

  ------------------------------------------------------ ----------------
  **Industry**                                           **Gases
                                                         Emitted**

  Aluminum production                                    PFCs, SF~6~

  HCFC-22 manufacture                                    HFC-23

  High-tension electrical equipment                      SF~6~

  Industrial Use of Hydrocarbons, Perfluorocarbons, and  HFCs, PFCs,
  Sulfur Hexafluoride as Substitutes for Ozone-Depleting SF~6~
  Substances, including use and assembly of              
  refrigeration and air conditioning equipment, open and 
  closed cell foam blowing, leakage from fire            
  extinguishers, use of solvents, and other              
  miscellaneous uses                                     

  Magnesium production                                   SF~6~

  Semiconductor manufacture                              HFCs, PFCs,
                                                         SF~6~
  ------------------------------------------------------ ----------------

This guidance does not attempt to provide detailed coverage of
estimation methods for the diversity of end-uses for high GWP gases. In
many cases, reporters are referred to other documented emissions
estimation authorities and resources. In those instances, ratings are
provided for the referenced estimation methods.

**1.E.4.4.1 Aluminum Production**

A number of high GWP gases are emitted during different stages of
aluminum production and processing. Two PFCs, tetrafluoromethane (CF~3~)
and hexafluoroethane (C~2~F~6~), are emitted during the smelting
process. Sulfur hexafluoride (SF~6~) is used as a cover gas and emitted
in some aluminum foundries. For a discussion of how to estimate these
emissions, please refer to subsection 1.E.4.1.3, "Aluminum Production,"
above.

**1.E.4.4.2 HCFC-22 Production**

Trifluoromethane (HFC-23) is a high GWP greenhouse gas that is generated
as a byproduct during the manufacture of chlorodifluoromethane
(HCFC-22). Unlike the majority of HFC emissions, most HFC-23 emissions
are point-source emissions, emitted through the condenser vents of
HCFC-22 manufacturing plants. Reporters can estimate HFC-23 emissions
through either direct measurement or inference. Some HCFC-22
manufacturers may capture some of the HFC-23 byproduct and sell it for
use in various applications from which it is eventually emitted.
Captured HFC-23 should not be included in the inventory of the entity
(though all process, fugitive and other emissions associated with its
manufacture should always be included).

Continuous emission monitoring (CEM) of all of a plant's exhaust
streams[^135] can accurately measure HFC-23 emissions. Emission
estimates based on CEM data will be assigned a rating of "A," provided
they meet the quality assurance criteria discussed under subsection
1.E.3.1, "Direct Measurement," above.

If continuous monitoring is not available, emissions can be estimated
from periodic measurements of the exhaust streams. Reporters can
estimate emissions with periodic measurements by multiplying the
concentration of HFC-23 in the exhaust stream by the volumetric
flow-rate of the exhaust stream and by the time elapsed during the
reporting period. Emission estimates based on representative direct
measurement will be assigned a rating of "A," provided they meet the
quality assurance criteria discussed under subsection 1.E.3.1,"Direct
Measurement," above.

If direct measurement systems are not available, reporters can estimate
HFC-23 emissions using a production-based, emissions factor approach. In
the absence of plant-specific data, reporters can assume that HFC-23
emissions are equal to 4 percent of the quantity (by mass) of HCFC-22
produced.[^136] Some plants might employ HFC-23 abatement or capture
technologies. If reporters have an estimate for the rate of HFC-23
abatement, they should use it; if not, it should be assumed equal to
zero. HFC-23 emissions can be calculated using the following equation:

**HFC-23 emissions (tons) = 0.04 \* HCFC-22 produced (tons) \* (1 --
abatement factor (percent))**

Emissions estimates based on production data and a default factor that
are publicly documented and have been widely reviewed and adopted by a
public agency, a standards-setting organization or an industry group
such as the IPCC, U.S. EPA, or API are rated "B." Emission estimates
based on production data and other default factors will be assigned a
rating of "C."

Ratings of methods for estimating emissions from HCFC-22 production are
summarized in Table 1.E.37.

###### Table 1.E.37. Rating of Estimation Methods for HFC Emissions from HCFC-22 Production

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Continuous emissions monitoring                                  A

  Emission estimates based on representative, periodic direct      A
  measurement                                                      

  Default, uncontrolled emissions factor, abatement/capture        B
  technology reduction value if applicable, that are publicly      
  documented and have been widely reviewed and adopted by a public 
  agency, a standards-setting organization or an industry group    

  Other default, uncontrolled emissions factor, abatement/capture  C
  technology reduction value if applicable                         
  ---------------------------------------------------------------- ------------

**1.E.4.4.3. SF~6~ Emissions from Electrical Equipment**

Sulfur hexafluoride has various uses and emissions associated with
electrical equipment. The IPCC provides instructions for estimating
emissions from these sources. Reporters should consult IPCC Good
Practice Guidance[^137] for details about the various estimation
methods, which include mass balance by life cycle state of equipment
(IPCC Tier 3a), mass balance at the manufacturer and facility level
(IPCC Tier 3b), the inference method by life cycle stage using emissions
factors (IPCC Tier 2a), the inference method using IPCC default
emissions factors (IPCC Tier 2b), and the potential emissions method
(IPCC Tier 1). Table 1.E.38 lists these IPCC methods and their ratings.

###### Table 1.E.38. Rating of Estimation Methods for Sulfur Hexafluoride Emissions from Electrical Equipment

  ----------------------------------------------------------- ------------
  **Estimation Method**                                       **Rating**

  Mass balance by life cycle stage of equipment (IPCC Tier    A
  3a)                                                         

  Mass balance at the manufacturer and facility level (IPCC   A
  Tier 3b)                                                    

  Inference method by life cycle stage using emissions        B
  factors (IPCC Tier 2a)                                      

  Inference method using IPCC default emissions factors (IPCC C
  Tier 2b)                                                    

  Potential emissions method (IPCC Tier 1)                    D
  ----------------------------------------------------------- ------------

**1.E.4.4.4 Industrial Use and Production of Hydrofluorocarbons,
Perfluorocarbons and Sulfur Hexafluoride**

Many industries have historically used ozone-depleting substances in
their products. Following the passage of the Montreal Protocol and the
1990 Amendments to the Clean Air Act, however, the production and use of
these substances in the United States has widely been phased out and
replaced with a host of non-ozone-depleting substitutes, including
hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs). Although they do
not contribute to ozone depletion, the release of these chemicals is of
concern due to their very high global warming potentials and long
atmospheric lifetimes.

In addition to uses as substitutes for ozone depleting substances, HFCs,
PFCs, and SF~6~ are used in a wide variety of industrial
processes.[^138] Industrial uses of HFCs and PFCs include the
manufacture and use of refrigeration and air conditioning, fire
suppression and explosion protection, aerosol manufacture and use,
solvent cleaning, foam blowing, equipment sterilization, and the
manufacture of coatings, adhesives and inks. SF~6~ is commonly used to
insulate switchgear and circuit breakers (for explosion protection) in
semiconductor manufacture and aluminum and magnesium foundries. With the
exception of PFC emissions from aluminum and HFC-23 emissions from
HCFC-22 manufacture, emissions of HFCs, PFCs, and SF~6~ are largely
fugitive emissions associated with the prior purchase of manufactured
chemicals by these industries.

Where direct measurement of emission streams is impractical, estimates
can be derived from records of purchase or usage of those manufactured
chemicals. It is possible to visualize several potential situations:

-   *Consumptive use data are available*. For some sectors, including
    magnesium production and aerosol use, consumption data can be used
    to estimate emissions. Reporters should refer to the methodological
    guidance provided by IPCC's *Good Practice Guidance* noted above and
    the EPA's "Climate Leaders Protocol"[^139] and follow instructions
    on accounting for changes in equipment and chemical stock, which
    implicitly accounts for chemical recycling.

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-   *Maintenance or repair data are available*. This might occur with
    HFCs used as a refrigerant or sulfur hexafluoride used in electrical
    systems. In these instances, emissions may be calculated either by
    estimating the volume of gas lost as a result of each failure, or
    measuring the volume of gas added to replace assumed losses.
    Reporters should be aware, however, of the potential for recycling
    and for emissions from equipment that is being decommissioned or
    taken out of service, and take care to prevent double counting or
    not counting the associated emissions.

-   *Gas purchase data are available*. Industrial gases are presumably
    purchased for consumptive use, but reporters using purchase data
    need to be aware of the importance of tracking new equipment, the
    potential for chemical stock change (i.e., the reporter maintains a
    supply of gas, and the inventory changes will affect consumption),
    the potential for recycling, and unreplaced losses from
    decommissioned equipment.

In general, emissions estimates based on mass balance using consumptive
use data, when reinforced by taking into account losses from changes in
chemical stock, equipment scrappage, or recycling (if available), will
be the most accurate. Where consumptive use data are not available,
estimates based on gas purchase data can be reinforced by estimates of
stock change and losses from equipment scrappage and possible gains from
recycling. In most cases, very broad emission estimates can be made
using estimates of equipment stock data, though these estimates will
have a large margin of error.

This guidance does not attempt to provide reporters with complete
coverage of the methods needed to estimate emissions. Reporters are
urged instead to consult the sources listed in the tables for each end
use discussed below.

**1.E.4.4.4.1 Use of Refrigeration and Air Conditioning**

Many companies use refrigerating and/or air conditioning or cooling
facilities within the scope of their organizational boundaries. Typical
uses include domestic, mobile, and commercial unitary air conditioning
units, chillers, cold storage, retail food storage, refrigerated
transport, and heat pumps.[^140] Table 1.E.39 includes a list of sources
that currently provide methods for estimating emissions arising from the
use of these systems.

###### Table 1.E.39. Sources and Ratings for Estimating Emissions from Use of Air Conditioning and Refrigeration Equipment

+---------------------------------------------------------------+------+
| **EPA Climate Leaders**                                       | **   |
| *www.epa.gov/climateleaders/core.html*                        | Rati |
|                                                               | ng** |
+---------------------------------------------------------------+------+
| > Material Balance Method                                     | A    |
+---------------------------------------------------------------+------+
| > Simplified Material Balance Method                          | A    |
+---------------------------------------------------------------+------+
| **IPCC Good Practice Guidance**                               |      |
| *http://www.ipcc-nggip.iges.or.jp/public/gp/gpgaum.htm*       |      |
+---------------------------------------------------------------+------+
| > Mass Balance, or Top-Down Approach that does not rely on    | A    |
| > emissions factors                                           |      |
+---------------------------------------------------------------+------+
| **IPCC Revised 1996 Guidelines**                              |      |
| *www.ipcc-nggip.iges.or.jp/public/gl/invs6.html*              |      |
+---------------------------------------------------------------+------+
| > Tier 2 - Actual Emissions, using facility-specific          | A    |
| > emissions factors that have been demonstrated to be highly  |      |
| > representative                                              |      |
+---------------------------------------------------------------+------+
| Tier 2 - Actual Emissions, using reasonably representative    | B    |
| facility-specific emissions factors                           |      |
+---------------------------------------------------------------+------+
| > Tier 2 - Actual Emissions, using country-specific emissions | C    |
| > factors                                                     |      |
+---------------------------------------------------------------+------+
| > Tier 1 - Potential Emissions                                | D    |
+---------------------------------------------------------------+------+
| **California Climate Change Action Registry-General Reporting |      |
| Protocol** *www.climateregistry.org/protocols/grp*            |      |
+---------------------------------------------------------------+------+
| > Mass Balance Method                                         | A    |
+---------------------------------------------------------------+------+

Note: Equally rated methods may be fundamentally the same method
reported by different authorities.

The *Revised 1996 IPCC Guidelines for National Greenhouse Gas
Inventories* provides a "potential" (Tier 1) and an "actual" (Tier 2)
method for estimating emissions of high-GWP gas emissions from the
following industries and activities:

-   Open and closed cell foam blowing

-   Manufacture and assembly of refrigerating devices

-   Leakage from fire extinguishers

-   Use as solvents

-   Use of SF~6~ in high tension electrical equipment, circuit breakers
    and gas insulated switchgear

-   Miscellaneous use

Reporters should consult the IPCC guidelines for details about the
estimation methods. As indicated in Table 1.E.39, above, estimations
based on the mass balance method will be assigned a rating of "A," while
estimations based on other methodologies reported in the IPCC Revised
1996 Guidelines may be assigned a rating of A, B, C, or D, depending on
the assumed accuracy with which the reporter's emissions factors
represent actual rates (e.g., site-specific emissions factors are
assumed to be more representative than country-specific factors).

**1.E.4.4.5 Magnesium Production**

Sulfur hexafluoride (SF~6~) is used as a cover gas to prevent the
oxidation of molten magnesium during smelting, casting and other
production processes. It is generally accepted that none of the sulfur
hexafluoride is reacted with or consumed while used, but rather that it
is all emitted directly into the atmosphere after use.[^141] The amount
of sulfur hexafluoride emitted during magnesium production is thus equal
to the amount consumed:

**SF~6~ Emissions = SF~6~ Consumption**

For most reporters, consumption data can be easily inferred from
purchase data. If consumption or purchase data are not available,
reporters can estimate emissions using production data and a default
emissions factor. Table 1.E.40 provides emissions factors for six major
processes that use sulfur hexafluoride:

###### Table 1.E.40. SF~6~ Emissions Factors from Magnesium Production Processes

+----------------------------------+-----------------------------------+
| **Process**                      | **Emissions Factor**              |
|                                  |                                   |
|                                  | **(kg SF~6~ / metric ton Mg)**    |
+----------------------------------+-----------------------------------+
| Secondary Production             | 1.0                               |
+----------------------------------+-----------------------------------+
| Die Casting                      | 0.74                              |
+----------------------------------+-----------------------------------+
| Die Casting (small parts)        | 5.2                               |
+----------------------------------+-----------------------------------+
| Gravity Casting                  | 2                                 |
+----------------------------------+-----------------------------------+
| Wrought Products                 | 1                                 |
+----------------------------------+-----------------------------------+
| Anodes                           | 1                                 |
+----------------------------------+-----------------------------------+
| Source: U. S. Environmental      |                                   |
| Protection Agency, *Inventory of |                                   |
| U.S. Greenhouse Gas Emissions    |                                   |
| and Sinks: 1990-2000* (2003).    |                                   |
+----------------------------------+-----------------------------------+

Emission estimates based on consumption data will be assigned a rating
of "A." Estimates based on default emissions factors in Table 1.E.40
will be assigned a rating of "B."

Ratings of methods for estimating emissions from magnesium production
are summarized in Table 1.E.41.

###### Table 1.E.41. Rating of Estimation Methods for SF~6~ Emissions from Magnesium Production

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Mass balance using consumption data                              A

  Default emissions factors based on general activity data         B
  ---------------------------------------------------------------- ------------

**1.E.4.4.6 Semiconductor Manufacture**

The semiconductor manufacturing industry emits a variety of high global
warming potential gases, including fluorocarbons (CF~4~, C~2~F~6~,
C~3~F~8~, c-C~4~F~8~, and CHF~3~), and sulfur hexafluoride (SF~6~). The
relative quantity of each gas emitted (referred to collectively as
fluorinated compounds, FCs) is site-specific, and depends on the
processes employed, the machinery, and the specifications of the
manufacturing process. In general, though, FCs are emitted from two
distinct processes: plasma etching and chemical vapor deposition (CVD).

Direct monitoring of emissions from silicon manufacturing, through CEM
or periodic measurements, is rare because of its high cost and technical
difficulty. The *IPCC Good Practice Guidance and Uncertainty Management
in National Greenhouse Gas Inventories* outlines four general approaches
for estimating FC emissions from silicon manufacturing, three of which
are applicable to plant-level estimations.[^142] The methods are
differentiated by the level of production data they require, as follows:

-   *Tier 2a - Process-specific parameters:* company- or plant-specific
    data are available for the amount of gas used in each process or by
    each tool (or subset thereof), the amount of purchased but unused
    gas remaining in the shipping container, the amount of gas destroyed
    or transformed during the manufacturing process, the amount of gas
    transformed to CF~4~ during the manufacturing process, the amount of
    gas used by processes equipped with emission control technologies,
    and the fraction of gas destroyed by those technologies. Estimates
    based on these data will be assigned a rating of "A."

-   *Tier 2b - Process type-specific parameters:* company- or
    plant-specific data are available for the amount of gas used in each
    *type* of process or tool. Generic industry-wide values can be used
    for the amount of purchased but unused gas remaining in the shipping
    container, the amount of gas destroyed or transformed for each
    process type, the amount of gas transformed to CF~4~ for each
    process type, and the fraction of gas destroyed by emission control
    technologies. Plant-specific data should be used when available.
    Estimates based on these data will be assigned a rating of "B."

-   *Tier 2c - FC-specific parameters:* company- or plant-specific data
    are available for gas sales/purchases and for emission control
    technologies. Default values specified for Tier 2b can be used,
    though plant-specific data are preferable where available. Estimates
    based on these data are rated "C."

Reporters should consult the IPCC guidelines for the details of each
method.

Alternatively, the World Resources Institute/World Business Council for
Sustainable Development provides an automated worksheet that estimates
emissions based on characteristics of the semiconductors produced,
production data, and a choice of plant-specific or industry default
values.[^143] Estimates made using this worksheet will be assigned a
rating of "C," unless the company- or plant-specific data required for
the "B" rating are used, in which case the worksheet method is rated
"B."

Ratings of methods for estimating emissions from semiconductor
manufacturing are summarized in Table 1.E.42.

###### Table 1.E.42. Rating of Estimation Methods for High GWP Gas Emissions from Semiconductor Manufacturing

  ---------------------------------------------------------------- ------------
  **Estimation Method**                                            **Rating**

  Mass Balance at the specific process or tool level (IPCC Tier    A
  2a)                                                              

  Mass Balance at the process- or tool-type level (IPCC Tier 2b)   B

  Mass Balance using WRI/WBCSD spreadsheets with plant-specific    B
  data                                                             

  Mass Balance using site-specific purchase and abatement data     C
  (IPCC Tier 2c)                                                   

  Mass Balance using WRI/WBCSD spreadsheets with default factors   C
  ---------------------------------------------------------------- ------------

##### 1.E.4.5 Special Situations: Geologic Sequestration

In some cases, industrial reporters may capture some of the carbon
dioxide emitted from their industrial processes and use this carbon
dioxide for geologic sequestration, either through enhanced oil recovery
or injection into a permanent storage reservoir, such as a deep coal
seem or a saline aquifer. The specific capture technologies and storage
reservoirs for geologic sequestration are described further in Part G
along with the steps for tracking and reporting emissions from the
sequestration process.

In some situations, the industrial entity may undertake both the capture
and storage activity itself, but in other cases the entity may choose to
sell or transfer the captured carbon dioxide to another entity for final
sequestration. In either case, the reporter would need to track the
origin of all potential carbon dioxide emissions, including the fraction
that is being captured. However, it is the reporter's responsibility to
include it its inventory only those emissions of carbon dioxide that
occur from facilities it owns or controls.

If a fraction of carbon dioxide is captured and permanently sequestered
by the entity that created the carbon dioxide, then that fraction shall
be treated as a "negative emissions." These negative emissions offset an
equivalent amount of the entity's emissions from creating the carbon
dioxide. Part G describes accepted accounting methodologies for
sequestering carbon dioxide through enhanced resource recovery and
injection into a permanent storage reservoir. If an entity reports any
negative emissions from sequestering carbon, the entity must report on
all carbon dioxide sources and sinks that fall within the entity
boundary, including any fugitive emissions from handling the captured
gas. If the reporter uses additional energy in the form of fossil fuel
combustion or electricity to capture, separate, or compress the carbon
dioxide, direct or indirect emissions from this energy use should be
reported following guidance in Part C, "Stationary Combustion," and Part
D, "Indirect Emissions."

Some carbon dioxide is usually leaked after the point of capture due to
the additional steps involved with treating and compressing it to a
consistency amenable for transport. The entity in possession of the gas
at the time of emission is responsible for including such emissions in
its inventory. Most likely, the transfer would take place at the point
of input or output of a carbon dioxide pipeline, and the amount of
carbon dioxide sold would be recorded through flow meters set up to
measure the amount of gas supplied to or extracted from the pipeline.

**Technical Guidelines for Voluntary Reporting of Greenhouse Gases
Program**

**Chapter 1, Emission Inventories**

### Part F: Indirect Emissions

Outline

1.  Overview

> 2\. Indirect Emissions from the Purchase of Electricity, Heat and
> Cooling: Concepts
>
> 2.1. Emissions
>
> 2.2. Electricity
>
> 2.3. Steam/Hot Water
>
> 2.4. Chilled Water
>
> 2.5. Energy Consumption
>
> 2.6. Power Purchases / Acquisitions and Sales / Transfers
>
> 3\. Methods for Estimating Indirect Emissions
>
> 3.1. Electricity Imports (not from cogeneration)
>
> 3.2. Steam or Hot Water Imports (not from cogeneration)
>
> 3.3. Chilled Water Purchases
>
> 3.4. Electricity or Heat Supplied by a Combined Heat and Power
> Generator

**Technical Guidelines Chapter 1, Part F: Indirect Emissions**

#### 1.F.1 Overview

The General Guidelines provide that reporters must report indirect
emissions arising from the consumption of electricity, steam, and hot
and chilled water separately from direct emissions in their Emissions
Inventories. This section describes methods and standards for estimating
those emissions. Indirect emissions associated with other activities can
also be reported, but not included in Emission Inventories.

Most reporters will generate indirect emissions somewhere within their
organizational boundaries. For many reporters, most reportable emissions
will be indirect. Indirect emissions are emissions from outside the
organizational boundary of an entity that are the result of an entity\'s
energy use or other activities. These emissions are normally emitted by
another entity. The most commonly reported forms of indirect emissions
are caused by the consumption of electricity, steam, and hot and chilled
water. In general, estimation and reporting of indirect emissions
presents three challenges:

-   When indirect emissions are reported, the potential exists for
    reporting of the same emissions by more than one party.

-   The actions of the party that "owns" or controls the emission source
    directly may strongly influence the level of emissions.

-   The reporter may find it difficult or impossible to obtain
    information about an emission source that it does not own or
    control.

In most cases, energy products such as heat and electricity are
generated through the combustion of fossil fuels. In these cases,
indirect emissions are generated through stationary combustion. Although
these emissions are not generated directly by the reporting entity, all
reporters should know the concepts behind estimating emissions from
stationary combustion and some reporters will need to apply this
knowledge in the preparation of their reports. Throughout this section
reporters are asked to refer to Part C of this Chapter, "Stationary
Combustion." Reporters who are unfamiliar with the fundamentals of
stationary combustion or with estimating emissions from combustion
processes are strongly encouraged to read Part C.

The only facilities that will not report indirect emissions are those
that generate all of their thermal and electrical needs on-site or
within entity boundaries.[^144]

#### 1.F.2 Indirect Emissions from the Purchase of Electricity, Heat and Cooling: Concepts

Indirect emissions are those that result from the consumption of energy
at a given site that is provided by a remote source or supplier.
Indirect emissions are driven by facilities' consumption of "useful"
energy commodities (referred to herein as "energy products"), such as
heat and electricity. Energy products are typically generated by
harnessing the energy stored in a "less useful" form (e.g., fossil
fuels) and converting it to a more useful one (e.g., electricity). The
conversion is the process where emissions are generated.

Once an energy product has been generated, it is transmitted and
distributed[^145] to the site where it will be consumed. The three major
sources of indirect emissions are electricity purchases, heating/steam
purchases, and consumption of cooling products, such as chilled water.

In general, there are three factors to consider when estimating indirect
emissions: the quantity of energy product consumed, the emissions from
the generation of that product, and how much energy is lost to the
environment while transmitting the product to the site where it is
consumed. These components are related by the following equation:

**Indirect Emissions ~Reporting\ Entity~ = Emission Factor
~Energy\ Supplier~ (quantity emissions /unit of energy) \* Energy
consumption ~Reporting\ Entity~ (units of energy) \* Transmission Loss
Adjustment Factor (%)**

The typical arrangement when considering indirect emissions is that of a
consumer purchasing an energy product that is generated remotely and
sold by a dedicated supplier. There are, however, several other
scenarios that warrant special considerations, and these are discussed
below under "Energy Purchases and Sales."

##### 1.F.2.1 Emissions

Carbon dioxide (CO~2~), methane (CH~4~), and nitrous oxide (N~2~O) are
the principal greenhouse gases that are accounted for when estimating
indirect emissions. While carbon dioxide emissions should always be
reported, the standards for reporting nitrous oxide and methane
emissions depend on the source of the indirect emissions. While some
generating technologies produce no or virtually no nitrous oxide or
methane emissions, other technologies may produce them in significant
quantities.

##### 1.F.2.2 Electricity

Electricity generation accounts for approximately one-third of the
greenhouse gases emitted in the United States each year.[^146] Carbon
dioxide accounts for the vast majority (over 99.5 percent) of GHG
emissions from grid-generated electricity. Because methane and nitrous
oxide normally account for a combined total of less than 0.5 percent of
GHG emissions, reporters may decide to include them in the *de minimis*
emissions excluded from their reports.

Given that grid-supplied electricity originates from a changing mix of
generators embedded in an extensive, interconnected network through
which specific electricity flows are virtually impossible to document,
it is inaccurate to base emissions from grid-supplied electricity on
those of a single plant, utility, or even state. In most instances,
electricity will be purchased from a regulated utility[^147] or other
load-serving entity that operates within the context of a power control
region. In a specific power control region, electricity is provided by a
host of generators that are brought online by a regional authority
(usually a Regional Transmission Operator or an Independent System
Operator) according to changes in demand, transmission restrictions,
plant generating characteristics, environmental factors, and their own,
established dispatch order. In order to minimize the burden on reporters
and avoid possible gaming, most reporters must use regional emission
factors to be specified by the Energy Information Administration (EIA).
Only those reporters that purchase electricity directly from specific
generators will need to obtain information about how the electricity
they consume is generated (see discussion below).

Average regional emission rates by state-defined regions for
grid-supplied electricity will be provided by EIA and will be updated
periodically. Unless reporters know that their electricity is purchased
and delivered from a particular plant (see discussion below), reporters
should presume that power purchased from electricity utilities is
"grid-generated" power and can be reasonably represented with regional
emission factors. Under these conditions, the reporter should employ the
appropriate regional emission factor.

After heat or electricity is generated, it must travel some distance to
the load where it will be 'consumed'. During transmission, some portion
of it will be irreversibly lost. Resistance in electricity lines
converts some quantity of electricity into heat, which is dissipated
into the environment. Consequently, generators must produce a quantity
of energy that exceeds the final demand of the end user. An adjustment
factor for transmission losses will be incorporated into the emissions
factors provided by EIA. Therefore, reporters may accurately estimate
total indirect emissions by simply multiplying their energy consumption
data by the appropriate emissions factors.

In rare cases, customers purchase electricity that is generated by and
delivered from a specific generating plant. Direct sales might be
arranged through public utilities, independent suppliers via public
utilities, or directly with non-utility generators (NUGs). Directly
purchased electricity can originate from a variety of sources, including
diesel generators, cogeneration (i.e., combined heat and power \[CHP\])
plants,[^148] and renewable generators.

Due to the disparity in emissions from these various sources, reporters
whose facilities acquire electricity from a specific source should try
to obtain source-specific emissions information (i.e., emissions
factors, total purchased electricity from source and source adjustment
factor for system-specific transmission losses) from their electricity
supplier. Contrary to grid-supplied electricity, their supplier may emit
significant quantities of methane and nitrous oxide. If the supplier
does not record its emissions data, reporters should determine what
generation technology and fuel sources are employed to produce the
supplier's electricity. Reporters should then estimate the plant's
emissions factors using the methods outlined in Part C. In cases where
methane and nitrous oxide emissions are not included in the *de minimis*
emissions excluded from the entity's report, reporters should estimate
and record those emissions using the same method employed for estimating
methane and nitrous oxide emissions described in Part C.

Some reporters may be engaged in a green power-purchasing contract. Only
those reporters that have plant-specific contracts with renewable energy
providers may report such purchases. Reporters that buy power from the
grid must use the state-based emission factors specified by EIA and
treat the green power purchases as offset reductions (see Chapter 2,
Emission Reductions).

##### 1.F.2.3 Steam / Hot Water

Supplied steam or heat is usually generated from direct, documentable
sources of energy. If the source of the supplied heat is known,
reporters should account for the carbon dioxide, nitrous oxide, and
methane emissions. If a supplier can provide emission rates and an
adjustment factor for transmission losses, they should be used in
concert with purchased energy to calculate indirect emissions from
purchased heating. Otherwise, reporters should obtain information about
the fuel type and heat generation technology used by their supplier and
estimate emissions using the stationary combustion methods outlined in
Part C.

Like electricity, during the transmission of steam or hot water, some
portion of the heat energy will be irreversibly lost. While heat is
transported, some quantity of heat energy will be absorbed by the
environment due to imperfect insulation. Most heat generators will keep
records of transmission losses, which are highly variable and depend
largely on the network through which they are transported. Reporters
should try to obtain transmission loss data from their suppliers.
Reporters should incorporate the transmission loss adjustment factor,
which is defined by the following equation, into their indirect
emissions estimate:

**Transmission loss adjustment factor = 1 / (1- transmission loss (%))**

For example, if the transmission loss is 10 percent, the transmission
loss factor will be equal to

**1/(1-.1) = 1/0.9 = 1.11**

##### 1.F.2.4 Chilled Water

Some facilities will purchase "cooling" for either cooling or
refrigeration when they do not operate cooling compressors on-site.
Cooling comes in the form of a chilled substance---usually water.
Conceptually, purchased chilled water is similar to purchased heat or
steam, with the primary difference being the process employed to
generate the chilled water. As with purchased heat, the following
discussion applies only to facilities that are supplied with cooling by
an external party.

Chilled water is typically generated by pressurizing a gaseous substance
with a compressor and then allowing the substance to return to standard
pressure. When the pressure is released from the gas, it absorbs thermal
energy as it expands, lowering the temperature of the immediate
environment---or in this case, whatever product that is going to serve
as the "vehicle" for the cooling product. Generally, compressors are
powered by either an electrical motor or by a combustion engine.

During transmission from the supplier to the end-user, chilled water
will absorb energy from the environment, which will result in an
increase in the temperature of the chilled water. Consequently,
generators must chill water to a temperature below the temperature
required for the end-user to make up for these inevitable losses. Most
suppliers will keep records of transmission losses, which vary widely
based on the specific transmission system. Reporters must account for
the transmission losses using the transmission loss adjustment factor,
represented by the following equation:

**Transmission loss adjustment factor = 1 / (1- transmission loss (%))**

For example, if the transmission loss is 10 percent, the transmission
loss factor will be equal to

**1/(1-.1) = 1/0.9 = 1.11**

The ratio of cooling demand to energy input for a cooling plant is known
as the plant's "coefficient of performance" (COP). To estimate
emissions, reporters need to know either the plant-specific COP, which
is preferable, or which type of compressor their cooling supplier uses.
If the supplier's COP value is not available, default values are
provided based on the type of compressor. If the supplier uses a
combustion engine-driven compressor, reporters can calculate the
compressor's emissions using the stationary combustion methods outlined
in Part C. If the compressor is powered by an electric motor, reporters
should follow the steps for estimating indirect emissions from
electricity consumption discussed in this section. In addition to
plant-specific emissions or equipment data, reporters should try to
obtain transmission loss data from their suppliers. Reporters should
incorporate the transmission loss adjustment factor, defined above, into
their indirect emissions estimate.

#####  

##### 1.F.2.5 Energy Consumption

Knowing the amount of energy consumed is essential to estimating
indirect emissions. Fortunately, this amount is easily quantifiable
because electricity, steam, and heated or chilled water are usually
provided at a metered rate that reflects the energy content of the
product sold. Purchase records should provide adequate information about
the quantity of energy consumed. If an organization has a number of
buildings or devices that consume independently monitored electricity,
these must all be accounted for.

Unfortunately, some facilities do not independently monitor their energy
consumption. This is often true in the case of leased office space,
where utility bills can be bundled into the rental fee. In those
instances, energy use is usually monitored at the level of the entire
building.

If entity-level energy consumption data are not available, the following
"area" method can be used to estimate energy consumption[^149] (if
reporters do not have access to this information, a building manager may
be able to provide it):

**Energy Use ~Facility~ = (Area ~Facility~ / Area ~Building~) \* Energy
Consumption ~Building~**

Where:

**Energy Use ~Facility~ = The amount of energy consumed in an office**

> **space, leased property or other facility that is**
>
> **housed within a larger building**

**Area ~Facility~ = The area of the facility for which energy**

> **consumption is being estimated**

**Area ~Building~ = The total area of the building in which the
facility**

> **is housed**

**Energy Consumption ~Building~ = Aggregated energy consumption data for
the**

> **entire building**

Heat, electricity, and cooling are usually sold in different units.
Electricity is most commonly sold and metered by the kilowatt-hour
(kWh). Typical units for measuring and selling heat include British
thermal units (Btu, often expressed in units of millions \[MMBtu\]),
therms (equal to 100,000 Btu), and pounds of steam. Cooling is usually
sold in ton-hours. Reporters may encounter instances where it is useful
to express these terms in common units. Use the conversion factors
provided in Table 1.F.1 when it is necessary to convert between units.

Table 1.F.1. Common Conversion Factors for Power Consumption

  ------------------------------------------- ---------------------------
  1 kWh =                                     3412.13 Btu

  1 Therm =                                   100,000 Btu

  1 Gigajoule (Gj) =                          0.95 MMBtu^\*^

  1 ton/hour cooling =                        12,000 Btu

  ^\*^1 MMBtu equals 1 million Btu            
  ------------------------------------------- ---------------------------

It is common for steam to be measured in pounds of steam. In these
cases, reporters must calculate the quantity of heat extracted from the
steam, measured in MMBtu. This calculation requires measuring the
difference between the heat content (enthalpy) of the steam when
purchased and when at a reference temperature.[^150] In this case, the
reference temperature is that of saturated water at 212 degrees
Fahrenheit (enthalpy = 180 Btu/lb).[^151]

In some cases, suppliers will be able to provide the heat content of
their delivered steam; otherwise, reporters must estimate it themselves.
Estimating the heat content of the purchased steam requires monitoring
the steam's temperature and pressure. Enthalpy values for steam at
different temperatures and pressures are available in steam tables. A
condensed steam table is provided in Table 1.F.2, below.[^152]

Table 1.F.2. Condensed Table of Enthalpy Values for Steam and Saturated
Water

+---------------+----------+---------------------+-------------------+
| **Gauge       | **Steam  | **Enthalpy of Sat.  | **Enthalpy of     |
| Pressure      | Temp     | liquid (Btu/lb)**   | Steam**           |
| (psig)**      | (*       |                     |                   |
|               | *º**F)** |                     | **(Btu/lb)**      |
+---------------+----------+---------------------+-------------------+
|               |          |                     |                   |
+---------------+----------+---------------------+-------------------+
|               |          |                     |                   |
+---------------+----------+---------------------+-------------------+
| 0             | 212.00   | 180.07              | 1150.4            |
+---------------+----------+---------------------+-------------------+
| 1.3           | 216.32   | 184.42              | 1152.0            |
+---------------+----------+---------------------+-------------------+
| 2.3           | 219.44   | 187.56              | 1153.1            |
+---------------+----------+---------------------+-------------------+
| 5.3           | 227.96   | 196.16              | 1156.3            |
+---------------+----------+---------------------+-------------------+
| 10.3          | 240.07   | 208.42              | 1160.6            |
+---------------+----------+---------------------+-------------------+
| 15.3          | 250.33   | 218.82              | 1164.1            |
+---------------+----------+---------------------+-------------------+
| 20.3          | 259.28   | 227.91              | 1167.1            |
+---------------+----------+---------------------+-------------------+
| 25.3          | 267.25   | 236.03              | 1169.7            |
+---------------+----------+---------------------+-------------------+
| 30.3          | 274.44   | 243.36              | 1172.0            |
+---------------+----------+---------------------+-------------------+
| 40.3          | 287.07   | 256.30              | 1175.9            |
+---------------+----------+---------------------+-------------------+
| 50.3          | 297.97   | 267.50              | 1179.1            |
+---------------+----------+---------------------+-------------------+
| 60.3          | 307.60   | 277.43              | 1181.9            |
+---------------+----------+---------------------+-------------------+
| 70.3          | 316.25   | 286.39              | 1184.2            |
+---------------+----------+---------------------+-------------------+
| 80.3          | 324.12   | 294.56              | 1186.2            |
+---------------+----------+---------------------+-------------------+
| 90.3          | 331.36   | 302.10              | 1188.1            |
+---------------+----------+---------------------+-------------------+
| 100.0         | 337.90   | 308.80              | 1188.8            |
+---------------+----------+---------------------+-------------------+
| 110.3         | 344.33   | 315.68              | 1191.1            |
+---------------+----------+---------------------+-------------------+
| 120.3         | 350.21   | 321.85              | 1192.4            |
+---------------+----------+---------------------+-------------------+
| 125.3         | 353.02   | 324.82              | 1193.0            |
+---------------+----------+---------------------+-------------------+
| 130.3         | 355.76   | 327.70              | 1193.5            |
+---------------+----------+---------------------+-------------------+
| 140.3         | 360.50   | 333.24              | 1194.6            |
+---------------+----------+---------------------+-------------------+
| 150.3         | 365.99   | 338.53              | 1195.6            |
+---------------+----------+---------------------+-------------------+
| 160.3         | 370.75   | 343.57              | 1196.5            |
+---------------+----------+---------------------+-------------------+
| 180.3         | 379.67   | 353.10              | 1198.0            |
+---------------+----------+---------------------+-------------------+
| 200.3         | 387.89   | 361.91              | 1199.3            |
+---------------+----------+---------------------+-------------------+
| 225.3         | 397.37   | 372.12              | 1200.6            |
+---------------+----------+---------------------+-------------------+
| 250.3         | 406.11   | 381.60              | 1201.7            |
+---------------+----------+---------------------+-------------------+
| Source:       |          |                     |                   |
| Center for    |          |                     |                   |
| Energy        |          |                     |                   |
| Efficiency    |          |                     |                   |
| and Renewable |          |                     |                   |
| Energy,       |          |                     |                   |
| *Process /*   |          |                     |                   |
|               |          |                     |                   |
| *Equipment    |          |                     |                   |
| Heat          |          |                     |                   |
| Recovery,*    |          |                     |                   |
| web site:     |          |                     |                   |
| www.ceere.    |          |                     |                   |
| org/iac/asses |          |                     |                   |
| sment%20tool/ |          |                     |                   |
| ARC2243.html. |          |                     |                   |
+---------------+----------+---------------------+-------------------+

The heat content of the purchased steam can now be calculated using the
following equation:

**Energy Content ~Purchased\ Steam~ (MMBtu) = \[Enthalpy
~Purchased\ Steam~ (Btu/lb) -- 180 (Btu/lb)\]**

**\* \[Steam Consumed (lbs)\] \* \[1MMbtu / 1,000,000 Btu\]**

##### 1.F.2.6 Power Purchases / Acquisitions and Sales / Transfers

The majority of reporters reading this section will be reporting for
facilities that only import power, although some may also export power.
Power imports include power purchased or otherwise acquired from a
direct supplier or utility. Power exports can include power that is
generated on-site and provided to another user, or power that is
purchased from a separate supplier and subsequently resold to another
end user (e.g., retail power purchases). In general, reporters should
not report any indirect emissions associated with purchased power that
is subsequently re-sold or otherwise exported.

#### 1.F.3 Methods for Estimating Indirect Emissions

##### **1.F.3.1 Electricity Imports (not from cogeneration)**[^153]

1)  **Estimate Total Electricity Consumption**

> Reporters should begin by calculating the total quantity of
> electricity purchased for use by their entity. Care should be taken to
> include all relevant facilities and independently metered electricity
> consuming devices. If electricity consumption is metered and recorded
> by the organization, those data should be used. Otherwise, purchase
> records or utility/supplier bills will provide an accurate measure of
> electricity consumption. These data are usually measured in kWh. If
> direct consumption records are not available, estimate consumption
> using the "area" method outlined above, under "Energy Consumption."

2)  **Determine an Appropriate Emission Factor**

> Once electricity consumption has been estimated, reporters must find
> an emission factor for their electricity source. For the vast majority
> of electricity users, electric power is supplied from a grid, and
> reporters should use an emission factor that represents the average
> emissions from state-based region where the supplier is located. These
> emission factors will be provided by EIA. The emission factors
> provided will have been adjusted to account for transmission losses.
>
> For the few reporters whose electricity is supplied directly from a
> known source, emissions data specific to that source should be used.
> Purchases from "known sources" refer to power that is supplied from a
> dedicated plant or source that can be specifically identified. "Known
> sources" do not include specific utilities, suppliers or known power
> regions; generator-specific information is required. Entities might
> purchase power from dedicated sources under specific contracts
> arranged through utilities or independent power suppliers, or under
> contracts arranged directly with generators (for purchases from CHP
> plants, refer to the discussion on Electricity or Heat Supplied by a
> Combined Heat and Power Generator, below). If available, reporters
> should use specific annual emissions data for known sources. If only
> the type of the generating plant is known, default emission rates in
> Table 1.F.3 can be used. If accounting for nitrous oxide and methane
> emissions, and emission factors are available, reporters should use
> them.

+-----------------------------------+----------+------+---+---+------+
| ###### Tabl                       |          |      |   |   |      |
| e 1.F.3. Carbon Dioxide Emission  |          |      |   |   |      |
| Rates for Various Generator Types |          |      |   |   |      |
+-----------------------------------+----------+------+---+---+------+
| Carbon Coefficients of Common     |          |      |   |   |      |
| Fuels ^\*^                        |          |      |   |   |      |
+-----------------------------------+----------+------+---+---+------+
| Fuel                              | **Coal** | *    | * |   | **Di |
|                                   |          | *Nat | * |   | stil |
|                                   |          | ural | R |   | late |
|                                   |          | G    | e |   | O    |
|                                   |          | as** | s |   | il** |
|                                   |          |      | i |   |      |
|                                   |          |      | d |   |      |
|                                   |          |      | u |   |      |
|                                   |          |      | a |   |      |
|                                   |          |      | l |   |      |
|                                   |          |      | O |   |      |
|                                   |          |      | i |   |      |
|                                   |          |      | l |   |      |
|                                   |          |      | * |   |      |
|                                   |          |      | * |   |      |
+-----------------------------------+----------+------+---+---+------+
| Emission Factor (kg CO~2~ /       | 93.5     | 52.8 | 7 |   | 72.4 |
| MMBtu)                            |          |      | 8 |   |      |
+-----------------------------------+----------+------+---+---+------+
| Emission Factors for a Variety of |          |      |   |   |      |
| Generator Types                   |          |      |   |   |      |
+-----------------------------------+----------+------+---+---+------+
| ######## Generator Type           | **Heat   | Fuel |   | * |      |
|                                   | Rate -   | Type |   | * |      |
|                                   | HHV**    |      |   | E |      |
|                                   | ^\*\*^   |      |   | m |      |
|                                   | **(MMBtu |      |   | i |      |
|                                   | / kWh)** |      |   | s |      |
|                                   |          |      |   | s |      |
|                                   |          |      |   | i |      |
|                                   |          |      |   | o |      |
|                                   |          |      |   | n |      |
|                                   |          |      |   | F |      |
|                                   |          |      |   | a |      |
|                                   |          |      |   | c |      |
|                                   |          |      |   | t |      |
|                                   |          |      |   | o |      |
|                                   |          |      |   | r |      |
|                                   |          |      |   | * |      |
|                                   |          |      |   | * |      |
|                                   |          |      |   |   |      |
|                                   |          |      |   | * |      |
|                                   |          |      |   | * |      |
|                                   |          |      |   | ( |      |
|                                   |          |      |   | k |      |
|                                   |          |      |   | g |      |
|                                   |          |      |   | C |      |
|                                   |          |      |   | O |      |
|                                   |          |      |   | ~ |      |
|                                   |          |      |   | 2 |      |
|                                   |          |      |   | ~ |      |
|                                   |          |      |   | / |      |
|                                   |          |      |   | k |      |
|                                   |          |      |   | W |      |
|                                   |          |      |   | h |      |
|                                   |          |      |   | ) |      |
|                                   |          |      |   | * |      |
|                                   |          |      |   | * |      |
+-----------------------------------+----------+------+---+---+------+
| Advanced Combustion Turbine       | 0.0094   | Nat  |   | 0 |      |
|                                   |          | ural |   | . |      |
|                                   |          | Gas  |   | 5 |      |
|                                   |          |      |   | 0 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Resi |   | 0 |      |
|                                   |          | dual |   | . |      |
|                                   |          | Oil  |   | 7 |      |
|                                   |          |      |   | 3 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Di   |   | 0 |      |
|                                   |          | stil |   | . |      |
|                                   |          | late |   | 6 |      |
|                                   |          | Oil  |   | 8 |      |
+-----------------------------------+----------+------+---+---+------+
| Advanced Gas / Oil Combined Cycle | 0.0070   | Nat  |   | 0 |      |
|                                   |          | ural |   | . |      |
|                                   |          | Gas  |   | 3 |      |
|                                   |          |      |   | 7 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Resi |   | 0 |      |
|                                   |          | dual |   | . |      |
|                                   |          | Oil  |   | 5 |      |
|                                   |          |      |   | 5 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Di   |   | 0 |      |
|                                   |          | stil |   | . |      |
|                                   |          | late |   | 5 |      |
|                                   |          | Oil  |   | 1 |      |
+-----------------------------------+----------+------+---+---+------+
| Conventional Combustion Turbine   | 0.0109   | Nat  |   | 0 |      |
|                                   |          | ural |   | . |      |
|                                   |          | Gas  |   | 5 |      |
|                                   |          |      |   | 8 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Resi |   | 0 |      |
|                                   |          | dual |   | . |      |
|                                   |          | Oil  |   | 8 |      |
|                                   |          |      |   | 5 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Di   |   | 0 |      |
|                                   |          | stil |   | . |      |
|                                   |          | late |   | 7 |      |
|                                   |          | Oil  |   | 9 |      |
+-----------------------------------+----------+------+---+---+------+
| Conventional Gas / Oil Combined   | 0.0075   | Nat  |   | 0 |      |
| Cycle                             |          | ural |   | . |      |
|                                   |          | Gas  |   | 4 |      |
|                                   |          |      |   | 0 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Resi |   | 0 |      |
|                                   |          | dual |   | . |      |
|                                   |          | Oil  |   | 5 |      |
|                                   |          |      |   | 9 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Di   |   | 0 |      |
|                                   |          | stil |   | . |      |
|                                   |          | late |   | 5 |      |
|                                   |          | Oil  |   | 4 |      |
+-----------------------------------+----------+------+---+---+------+
| Distributed Generation - Baseload | 0.0094   | Nat  |   | 0 |      |
|                                   |          | ural |   | . |      |
|                                   |          | Gas  |   | 5 |      |
|                                   |          |      |   | 0 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Resi |   | 0 |      |
|                                   |          | dual |   | . |      |
|                                   |          | Oil  |   | 7 |      |
|                                   |          |      |   | 3 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Di   |   | 0 |      |
|                                   |          | stil |   | . |      |
|                                   |          | late |   | 6 |      |
|                                   |          | Oil  |   | 8 |      |
+-----------------------------------+----------+------+---+---+------+
| Distributed Generation - Peak     | 0.0104   | Nat  |   | 0 |      |
|                                   |          | ural |   | . |      |
|                                   |          | Gas  |   | 5 |      |
|                                   |          |      |   | 5 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Resi |   | 0 |      |
|                                   |          | dual |   | . |      |
|                                   |          | Oil  |   | 8 |      |
|                                   |          |      |   | 1 |      |
+-----------------------------------+----------+------+---+---+------+
|                                   |          | Di   |   | 0 |      |
|                                   |          | stil |   | . |      |
|                                   |          | late |   | 7 |      |
|                                   |          | Oil  |   | 5 |      |
+-----------------------------------+----------+------+---+---+------+
| Fuel Cells                        | 0.0075   | Nat  |   | 0 |      |
|                                   |          | ural |   | . |      |
|                                   |          | Gas  |   | 4 |      |
|                                   |          |      |   | 0 |      |
+-----------------------------------+----------+------+---+---+------+
| Integrated Coal-Gasification      | 0.0080   | Coal |   | 0 |      |
| Combined Cycle                    |          |      |   | . |      |
|                                   |          |      |   | 7 |      |
|                                   |          |      |   | 5 |      |
+-----------------------------------+----------+------+---+---+------+
| Scrubbed Coal -- New              | 0.0090   | Coal |   | 0 |      |
|                                   |          |      |   | . |      |
|                                   |          |      |   | 8 |      |
|                                   |          |      |   | 4 |      |
+-----------------------------------+----------+------+---+---+------+
| **Source:** \* U.S. Energy        |          |      |   |   |      |
| Information Administration,       |          |      |   |   |      |
| *Assumptions to the Annual Energy |          |      |   |   |      |
| Outlook 2003,* Table 2 (2003),    |          |      |   |   |      |
| web site:                         |          |      |   |   |      |
| www.eia.doe.go                    |          |      |   |   |      |
| v/oiaf/aeo/assumption/index.html. |          |      |   |   |      |
|                                   |          |      |   |   |      |
| ^\*\*^ U.S. Energy Information    |          |      |   |   |      |
| Administration, *Assumptions to   |          |      |   |   |      |
| the Annual Energy Outlook 2003,*  |          |      |   |   |      |
| Table 40 (2003), web site:        |          |      |   |   |      |
| www.eia.doe.go                    |          |      |   |   |      |
| v/oiaf/aeo/assumption/index.html. |          |      |   |   |      |
+-----------------------------------+----------+------+---+---+------+

3)  **Estimate Indirect Emissions**

> Reporters who are among the majority of electricity users whose
> electric power is supplied from a grid should use the following
> formula to estimate emissions:

Indirect Emissions ~Reporting\ Entity~ = Consumption ~Reporting\ Entity~
\* Emissions Factor ~Supplier~

> Reporters with electricity supplied directly from a known source
> should use the following formula to estimate emissions:

Indirect Emissions ~Reporting\ Entity~ = Consumption ~Reporting\ Entity~
\* Transmission loss adjustment factor \* Emission Factor ~Supplier~

Ratings of emissions estimates will be assigned based on the data used,
as described in Table 1.F.6.

###### Table 1.F.4. Rating of Estimation Methods for Indirect Emissions from Electricity Imports

  ---------------------------------------------------------- ------------
  **Estimation Method / Data Used**                          **Rating**

  Measured electricity consumption in conjunction with       A
  source-specific, generator-type or default regional or     
  default national emission rates and system-specific or     
  default transmission loss factor\*                         

  "Area" method estimate of electricity consumption in       B
  conjunction with source-specific, generator-type or        
  default regional or default national emission rates and    
  system-specific or default transmission loss factor\*      

  \* Transmission loss factor applies only to reporters      
  whose electricity is supplied directly from a known        
  source. Regional emissions factors presented in this       
  section have already been adjusted for transmission        
  losses.                                                    
  ---------------------------------------------------------- ------------

##### **1.F.3.2 Steam or Hot Water Imports (not from cogeneration)**[^154]

Steam and hot water are used to provide office heating in the commercial
sector and process heating in the industrial sector. As with all
indirect emissions, it is important to remember that the discussion
included here applies *only* to facilities that purchase or otherwise
acquire heat energy from an external supplier. Facilities that operate
boilers, generators or other devices to supply their own thermal energy
should refer to Part C for stationary combustion methods to estimate
those direct emissions. Facilities that this discussion applies to
typically include leased office spaces that purchase heating from
building managers, and commercial or industrial facilities that purchase
heating from a district heating system.

**1) Estimate Purchased Heat/Steam**

Reporters should begin by calculating the quantity of steam/hot water
purchased. If steam imports are metered and recorded by the
organization, those data should be used. Otherwise, purchase records or
utility/supplier bills will provide an accurate measure of delivered
steam/heat, which may be recorded in terms of energy, mass or volume. If
the only available emission factors require data in a metric that is
different from the metric in which the data are reported, use the
conversion factors listed in Table 1.F.1 to make the necessary
conversion. If direct consumption records are not available, estimate
consumption using the "area" method outlined above, under "Energy
Consumption."

**2) Obtain an Appropriate Emission Factor**

If possible, an emission factor (tons CO~2~ / MMBtu heat generated)
should be obtained directly from the supplier. If the supplier cannot
provide one, reporters can use a default emissions value of 78.95 kg
CO~2~/MMBtu.[^155]In cases where methane and nitrous oxide emissions are
not included in the *de minimis* emissions excluded from the entity's
report, reporters should use default emissions factors from Part C if
source-specific emissions factors are not available.

**3) Estimate Emissions**

> Using the emission factor obtained above, indirect emissions from
> purchased hot water and steam can be calculated with information on
> the quantity of energy consumed,[^156] and transmission losses. These
> factors are related by the following formula:

**Indirect Emissions = Energy Consumption \* Emission factor
~Supplier~**

**\* Transmission loss adjustment factor**

If reporters cannot obtain an estimate of transmission losses from their
supplier, they can use a default loss rate of 10 percent.

Ratings of emissions estimates will be assigned based on the data used,
as described in Table 1.F.5.

###### Table 1.F.5. Rating of Estimation Methods for Indirect Emissions from Steam or Hot Water Imports

  ------------------------------------------------------- ---------------
  Estimation Method / Data Used                           **Rating**

  Measured heat consumption in conjunction with           A
  source-specific emission factor and source-specific or  
  default transmission loss factor                        

  Measured heat consumption in conjunction with default   B
  emission factor and source-specific or default          
  transmission loss factor                                

  "Area" method estimate of heat consumption in           C
  conjunction with source-specific emission factor and    
  source-specific or default transmission loss factor     

  "Area" method estimate of heat consumption in           D
  conjunction with default emission factor and            
  source-specific or default transmission loss factor     
  ------------------------------------------------------- ---------------

##### **1.F.3.3 Chilled Water Purchases**[^157]

Reporters can estimate emissions associated with purchased chilled water
by using values for the COP of the supplying plant. If reporters cannot
obtain plant-specific COP values, default values are provided.

**1) Estimate Cooling Demand**

Refer to monthly cooling bills to estimate the yearly cooling demand of
the relevant facility. If the supplied cooling is reported in ton-hours
of cooling, convert it to million Btus (MMBtu) at the rate of 12,000 Btu
per ton-hour as illustrated in Table 1.F.1.

**2) Estimate Supplier's COP**

If it is possible to obtain specific information about a cooling plant's
COP, use this information. If not, a cooling supplier should be able to
tell reporters the type of chiller they use in their cooling plant.
Default COP values for different chiller types are provided in Table
1.F.6.

###### Table 1.F.6. Default Coefficient of Performance Values for Various Chiller Types

  ----------------------- --------------------------- -------------------
  **Chiller Type**        **Coefficient of            **Energy Source**
                          Performance**               

  Absorption Chiller      0.8                         Natural Gas

  Engine-Driven Chiller   1.2                         Natural Gas

  Electric-Driven Chiller 4.2                         Electricity

  **Source:** California                              
  Climate Action                                      
  Registry, *General                                  
  Reporting Protocol*                                 
  (October 2002).                                     
  ----------------------- --------------------------- -------------------

**3) Calculate Cooling Plant Inputs from Energy Demand**

The amount of energy input into the cooling system to meet an entity's
demand can be estimated by dividing entity-cooling demand by the COP of
the cooling plant (note that energy input for natural gas systems is
denominated in thermal energy and energy input for electrical systems is
denominated in electrical energy). The cooling plant energy input is
represented by the following equation:

**Energy Input ~Cooling\ plant~ = (Cooling Demand ~Reporting\ Entity~ \*
Transmission loss adjustment factor)**

**/ (COP ~Cooling\ plant~)**

> Reporters should try to obtain an estimate of transmission losses from
> their supplier. If their supplier cannot provide one, they can use a
> default loss rate of 10 percent.[^158]

**4) Calculate Emissions**

If an engine-driven compressor drives the cooling plant, emissions from
its fuel consumption can be estimated using the energy input value
calculated above and the methods for estimating emissions from
stationary combustion detailed in Part C, "Stationary Combustion."

If an electricity-driven compressor drives the cooling plant, emissions
from its electricity use can be estimated using the energy input value
calculated above and the methods for estimating indirect emissions from
electricity use detailed above.

Ratings of emissions estimates will be assigned based on the data used,
as described in Table 1.F.7.

###### Table 1.F.7. Rating of Estimation Methods for Indirect Emissions from Chilled Water Purchases

  --------------------------------------- -------------------------------
  **Estimation Method / Data Used**       **Rating**

  Measured chilled water consumption data Same rating as given to the
  used in conjunction with                method used to calculate
  source-specific COP and a               emissions (see Step 4)
  source-specific or default transmission 
  loss factor                             

  Measured chilled water consumption data One value rating lower than the
  used in conjunction with default COP    rating given to the method used
  and source-specific or default          to calculate emissions (see
  transmission loss factor                Step 4)

  "Area" method estimates of chilled      Two value ratings lower than
  water consumption used in conjunction   the rating given to the method
  with source-specific COP and            used to calculate emissions
  source-specific or default transmission (see Step 4)
  loss factor                             

  "Area" method estimates of chilled      D
  water consumption in conjunction with   
  default COP and source-specific or      
  default transmission loss factor        
  --------------------------------------- -------------------------------

##### 

##### 1.F.3.4 Electricity or Heat Supplied by a Combined Heat and Power Generator

##### 

Unlike the majority of electricity users, most purchasers of thermal
energy know the specific generator, and their energy purchases are
covered by a contract with that source. Only those users that have a CHP
plant-specific contract for heat or power should use this method.

Unlike the topics discussed above, CHP is not a specific energy product.
The term refers to a power generating arrangement that simultaneously
generates electricity and useful heat. In the process of producing
electricity, combustion generators give off significant quantities of
heat. In most generating processes, this heat is lost to the
environment. In contrast, CHP systems capture and redirect this heat so
that it can be applied in a usable manner. The benefit of capturing and
using this "waste" heat is an increase in fuel use efficiency.

Combined heat and power is used in applications where there is a
concurrent demand for thermal and electrical energy.[^159] The benefit
of meeting these demands with a CHP generator is that the fuel use
efficiency of most CHP systems is greater than what would be achieved by
meeting electrical and thermal demands by separate processes. Whereas
many facilities consume both the thermal and electrical energy produced
by CHP systems on-site, others may find it profitable to sell ("export")
either thermal and/or electrical energy if they generate either of these
in surplus. If purchasing power from an independent supplier, reporters
should ascertain whether or not it is generated by a CHP system.

Entities that use all of the thermal and electrical output of a CHP
plant that they own and operate should use the methods outlined in Part
C, "Stationary Combustion," to estimate emissions. If an entity consumes
all of the heat *and* electricity output from an external supplier's CHP
plant, estimating emissions is straightforward: indirect emissions will
be equal to the total emissions of the CHP plant. When purchasing a
portion of plant output of either electricity or heat alone, the
procedure is somewhat more involved than it is for dedicated generating
sources, and is outlined below.

Because CHP plants simultaneously produce electricity and usable heat
from a single fuel source and generating process, care must be taken not
to "double count" emissions by allocating total emissions to both
products. Instead, reporters must account for emissions in a way that
reflects the relative "share" that heat and electricity contribute to
overall CHP emissions, respectively. In some cases, reporters may be
able to obtain emission rates for thermal and electrical generation
directly from CHP managers. When possible, these figures should be used.
In cases where these data are not available, reporters can estimate
emissions from thermal and electrical generation on their own, using the
method described below.[^160]

**1.F.3.4.1 Indirect Emissions from Electricity and Heat Purchases from
Offsite CHP Plants**

**1) Estimate Purchased Electricity/Heat**

Estimate the quantities of electricity and/or heat purchased from a
cogeneration supplier. Refer to bills or sales records for this
information.

**2) Acquire Total Emissions and Power Production Data for the CHP
Plant**

Before estimating emissions from individual heat or electricity
purchases, reporters should contact their CHP plant manager for
information about the total quantity of emissions generated by the CHP
plant, and the thermal and electrical generating efficiency of the
plant. If total emissions for the plant have not been calculated, either
the reporter or the plant manager can estimate them from total fuel use
data using the methods outlined in Part C, "Stationary Combustion," of
the Technical Guidelines.

**3) Allocate** **Emissions to Electricity and Thermal Generation**

> -The following formulas allocate emissions to the thermal and
> electrical generating streams of the CHP plant based on the efficiency
> of thermal and electrical generation:[^161]
>
> **CHP Plant** **Emissions~Thermal~** **= Emissions~Total~** **\*
> (O~T~/ E~T~) / ((O~T~** **/ E~T~) + (O~E~/ E~E~))**
>
> **CHP Plant** **Emissions~Electricity~** **= Emissions~Total~** **-
> Emissions~Thermal~**
>
> **~Thermal~** **t~Thermal~ency** **= e~Total\ rmal~**

Wh

> **CHP Plant** **Emissions~Thermal~** **= Emissions attributable to
> thermal generation**
>
> **CHP Plant** **Emissions~Electricity~** **= Emissions attributable to
> electricity generation**
>
> **CHP Plant** **Emissions~Total~** **= Total emissions from the CHP
> plant**
>
> **CHP Plant** **O~Thermal~** **(O~T~)** **= Thermal generation,
> measured in MMBtu**
>
> **CHP Plant** **O~Electricity~** **(O~E~)** **= Electrical generation,
> measured in MMBtu**[^162]
>
> **CHP Plant** **E~Thermal~** **(E~T~)** **=** **Efficiency of thermal
> energy generation, expressed**
>
> **as a decimal percentage**
>
> **CHP Plant** **E~Electricity~** **(E~E~)** **=** **Efficiency of
> electrical energy generation**
>
> **, expressed as a decimal percentage**

If the efficiency of thermal energy generation (Efficiency ~Thermal~) is
unknown, reporters may use a default value of 0.8. If the efficiency of
electrical energy generation (Efficiency ~Electricity~) is unknown,
reporters may use a default value of 0.35.

**4) Estimate Emissions from Own Use**

> Reporters should estimate their own indirect emissions by multiplying
> the total emissions at the CHP plant by the ratio of their energy
> consumption to plant energy production. Estimate emissions using the
> following equations:
>
> Reporter Emissions from Purchased Thermal Energy = \[CHP Plant
> Emissions~Thermal~ (tons)\] \* \[Reporter Purchased Thermal Energy
> (MMBtu) / CHP Plant O~Thermal~ (MMBtu)\] \* Transmission loss
> adjustment factor
>
> Reporter Emissions from Purchased Electricity = \[CHP Plant
> Emissions~Electricity~ (tons)\] \* \[Reporter Purchased Electricity
> (kWh) / CHP Plant O~Electricity~ (kWh)\]
>
> \* Transmission loss adjustment factor
>
> Reporters should try to obtain an estimate of transmission losses for
> thermal and electrical power from their supplier (the CHP operator).
> Most suppliers will keep records of transmission losses, which vary
> widely based on the specific transmission system. Reporters must
> account for the transmission losses using the transmission loss
> adjustment factor, represented by the following equation:

**Transmission loss adjustment factor = 1 / (1- transmission loss (%))**

> For example, if the transmission loss is 10 percent, the transmission
> loss factor will be equal to
>
> **1/(1-.1) = 1/0.9 = 1.11**
>
> If the supplier cannot provide a transmission loss factor, reporters
> may use a default loss rate of 10 percent for steam and hot water, and
> 6 percent for electricity. \[The 6 percent value is based roughly on
> typical electric system transmission and distribution losses.\]

**5) Sum Emissions**

> Reporters should add emissions from purchased steam and electricity to
> calculate the sum of indirect emissions from CHP-generated energy use.

Ratings of emissions estimates will be assigned based on the method
used, as described in Table 1.F.8.

###### ~Table\ 1.F.8.\ Rating\ of\ Estimation\ Methods\ for\ Indirect\ Emissions\ from\ Electricity\ and\ Heat\ Purchases\ from\ Offsite\ CHP\ Plants~

  ----------------------------------------- -----------------------------
  **Estimation Method / Data Used**         **Rating**

  Measured steam/electricity consumption    Same rating as given to the
  data used in conjunction with             method used to determine CHP
  source-specific emission rates and a      plant emissions as referenced
  source-specific or default transmission   in Step 2, above
  loss factor                               

  Measured steam/electricity consumption    One value rating lower than
  data used in conjunction with the method  the rating given to the
  provided for allocating fuel use to       method used to determine CHP
  thermal and electrical generation, and a  plant emissions as referenced
  specific or default transmission loss     in Step 2, above
  factor                                    

  "Area" method estimate of                 Two value ratings lower than
  steam/electricity consumption used in     the rating given to the
  conjunction with source-specific emission method used to determine CHP
  rates and a source-specific or default    plant emissions as referenced
  transmission loss factor                  in Step 42,above

  "Area" method estimate of                 D
  steam/electricity consumption used in     
  conjunction with the method provided for  
  allocating fuel use to thermal and        
  electrical generation, and a specific or  
  default transmission loss factor          
  ----------------------------------------- -----------------------------

**Technical Guidelines for Voluntary Reporting of Greenhouse Gases
Program**

**Chapter 1, Emission Inventories**

### Part G: Geologic Sequestration

Outline

> 1\. Overview
>
> 2\. Reporting on Carbon Dioxide Capture for Geologic Sequestration

2.1. Inventory Approach

2.2. Sources of Carbon Dioxide for Geologic Sequestration

> 3\. Accounting for Sequestered Carbon Dioxide Over Time
>
> 4\. Accounting Protocols for Geologic Sequestration Activities
>
> 5\. Fugitive Carbon Dioxide Emissions

5.1. Fugitive Emissions from the Extraction of Naturally Occurring
Carbon Dioxide

5.2. Fugitive Emissions from the Extraction of Carbon Dioxide from

Anthropogenic Sources

5.3. Fugitive Emissions from Transport and Processing

5.4. Fugitive Emissions from Injection and Extraction for Enhanced
Resource Recovery

6\. Direct and Indirect Emissions

6.1. Energy Used for the Carbon Dioxide Capture Process

6.2. Energy Used for the Carbon Dioxide Injection Process

6.3. Energy Used for Extraction for Enhanced Resource Recovery

7\. Post-Injection Seepage of Carbon Dioxide to the Atmosphere

**Technical Guidelines Chapter 1, Part G: Geologic Sequestration**

#### 1.G.1 Overview

Carbon sequestration - the practice of capturing and storing carbon
dioxide (CO~2~) - is a relatively new option for greenhouse gas
mitigation and consists of two types. First, through engineered
sequestration, carbon dioxide can be captured from the point of emission
and then stored in underground reservoirs, dissolved in deep oceans, or
converted to rock-like solid materials. Second, through biotic
(terrestrial and oceanic) sequestration, carbon dioxide can be removed
from the air and sequestered in natural sinks such as trees, grasses,
soils, or algae. This Part of Chapter 1 focuses on engineered carbon
sequestration via the use of permanent geologic storage sites, also
referred to as carbon capture and sequestration in underground
reservoirs; or simply, geologic sequestration. Terrestrial sequestration
is covered in Parts H and I. Engineered sequestration via ocean storage
and conversion to solid materials are still in the research stage and
are not covered in these Technical Guidelines.

Geologic carbon sequestration consists of the following three
components:

> *Capture*: The carbon dioxide must be captured from the source of
> emissions. A third of the current U.S. greenhouse gas emissions are
> from power plants, oil refineries, and other large point
> sources.[^163]
>
> *Transportation and Storage*: Following capture, carbon dioxide must
> be transported and stored. Captured carbon dioxide can be compressed
> and transported by a pipeline to a storage site. The United States is
> underlain by saline aquifers, depleted oil and natural gas reservoirs,
> and unmineable coal seams with the combined potential to store
> centuries' worth of carbon dioxide emissions.
>
> *Measurement, Monitoring and Verification*: Over the long term, stored
> carbon dioxide should be measured and monitored for both safety
> reasons and to ascertain if any leakage of the stored carbon dioxide
> occurs. Geologic sequestration is an emerging field; a few monitoring
> and measurement technologies are already in use today while others are
> still in the research and development phase. The guidance presented
> here is based on the reporting and monitoring approaches available at
> this time. As the field develops, the Department of Energy (DOE) will
> continue to review new studies and reporting rules for applicable
> information and, whenever appropriate, revise the reporting guidelines
> accordingly.

#### 1.G.2 Reporting on Carbon Dioxide Capture for Geologic Sequestration 

It is generally the reporter's responsibility to identify all
anthropogenic emissions of carbon dioxide that occur from facilities
owned or controlled by the reporter. For inventory reporting purposes,
any carbon dioxide produced and emitted to the atmosphere as a result of
combustion, reforming processes, or withdrawal from natural or man-made
geologic reservoirs is considered an emission. Under these guidelines,
captured carbon dioxide is also considered an emission and should be
reported as such in the inventory of the entity within which the capture
occurs.

Only those entities that both capture and sequester carbon dioxide
within their organizational boundaries may subtract from their
inventories the amount of carbon dioxide they have permanently stored in
a geologic reservoir. Entities that transfer captured anthropogenic
carbon dioxide for permanent storage by another entity may not subtract
these emissions from their emissions inventories, but may, under the
reduction guidelines described in Chapter 2, report such reductions if
they have an agreement with the entity that receives and permanently
sequesters these emissions.

To avoid double counting of sequestered carbon dioxide in the emissions
inventory and the assessment of net emission reductions, all entities
capturing carbon dioxide must include such captured gases in their
assessments of net emission reductions. Any reductions resulting from
permanently sequestered carbon dioxide must be calculated separately
using the special method for geologic sequestration provided in Chapter
2, Section 2.4.5.6.5.

Entities that receive anthropogenic carbon dioxide from another entity
do not report those emissions in their inventory, but may report a
reduction equal to the amount of carbon injected into storage if they
have taken the steps necessary to permanently store the carbon dioxide
and monitor that sequestration, as required by Chapter 2, Section
2.4.5.6.5. Alternatively, they may enter into agreements with the
entities that initially captured and transferred the carbon dioxide to
permit those capturing entities to report the resulting emission
reductions.

If an entity extracts or receives carbon dioxide from a naturally
occurring reservoir and uses this for injection purposes, such as
enhanced oil recovery (EOR), the extracted carbon dioxide must be
treated as an emission in that entity's inventory. This special
treatment of naturally occurring carbon dioxide is necessary to prevent
entities from claiming reductions from carbon dioxide that has been
tapped from a geologic reservoir.

Reporters that engage in carbon dioxide capture, transportation, and/or
storage, including enhanced resource recovery (ERR), should account for
all anthropogenic carbon dioxide emissions to the atmosphere that occur
within the reporter's entity boundary, including any leakage of carbon
dioxide from the geologic storage site and fugitive emissions from
processing plants and pipelines, injection wells, and enhanced resource
recovery sites. If more than one entity is involved in the capture,
transportation, and storage process, each of these entities are
responsible for any potential leakage or fugitive emissions that occur
within their respective reporting boundaries. Reporters are not
responsible for any naturally occurring carbon dioxide emissions that
may occur within the reporting boundary, but that are unrelated to the
enhanced oil recovery (EOR) or storage activity.

If a reporter injects captured or recovered carbon dioxide from power
generation and/or industrial processes into a geologic formation as part
of an EOR project, and withdraws carbon dioxide from that or another
reservoir for reuse at another site, the carbon dioxide that was
recovered during that process should be counted as emissions in the
inventory. Any physical leakage of captured carbon dioxide from the
permanent storage site measured within the current reporting year but
after the time of injection should also be treated as an emission. If an
entity recycles and stores recovered carbon dioxide in another
reservoir, the entity must use the special method for geologic
sequestration described in Chapter 2, Section 2.4.5.6.5 in order to
report an emission reduction from this activity.

If the reporter uses energy in the form of combusted fossil fuel or
electricity to compress, produce, separate, or inject carbon dioxide,
direct or indirect emissions from this energy use should be reported as
described in Parts C and F, respectively. The reporter will also need to
consider carbon dioxide that is dissolved or entrained in produced water
and oil from EOR and the resulting emissions. Even if an entity captures
carbon dioxide and transfers this carbon dioxide to another entity, the
capturing entity must report any additional emissions from handling the
captured carbon dioxide that occurs within its reporting boundary.
Similarly, the entity, or entities, receiving, transporting, and/or
injecting the carbon dioxide must report all direct and indirect
emissions from additional energy use that occurs within that entity's
boundary.

##### 1.G.2.1 Inventory Approach

A geologic sequestration project begins with a source of carbon dioxide
and ends with its injection and retention into a geologic storage
reservoir. In reporting a sequestration project, as with all types of
reporting under this system, the entity must provide accurate accounting
for greenhouse gases emitted to the atmosphere from each part of the
process.

Much of the information on accounting for emissions from stationary and
industrial sources is covered earlier in this Chapter. This Part focuses
on the accounting methodology for geologic carbon dioxide sequestration,
and includes:

-   Procedures for estimating fugitive emissions from carbon dioxide
    capture and geologic storage.

-   Accounting procedures to address fugitive emissions from the use of
    carbon dioxide for enhanced resource recovery.

-   Options for addressing potential physical leakage of carbon dioxide
    from storage reservoirs.

[]{.mark}

In some cases, small amounts of methane or nitrous oxides may reside in
the captured gas. In such cases, fugitive emissions and physical leakage
of these gases should be accounted for, using the same approaches as
those outlined below for carbon dioxide.

##### 1.G.2.2 Sources of Carbon Dioxide for Geologic Sequestration

Capture of carbon dioxide is most practical from highly concentrated
sources. In addition to carbon dioxide from naturally occurring
reservoirs,[^164] there are a number of industrial and energy combustion
processes that yield a highly concentrated stream of carbon dioxide,
amenable to geologic sequestration. As shown in Table 1.G.1, the amount
of carbon dioxide emitted from these high-concentration sources is
estimated to be 185 million metric tons of carbon dioxide per year
(MMmtCO~2~/yr). These sources are:

-   *Oxygen-blown gasification.* Synthetic gas (or "syngas") from an
    oxygen-fired gasifier is predominantly hydrogen and carbon dioxide.
    Carbon dioxide can be separated at high pressures from syngas prior
    to use, and carbon dioxide capture can be combined with sulfur
    removal.

-   *Natural gas processing.* Carbon dioxide accounts for up to 90
    percent of the gas in certain natural gas reservoirs. Carbon dioxide
    volume must be reduced to 1 to 2 percent to achieve the minimum Btu
    requirement for pipeline-quality natural gas. Chemical or physical
    absorbents used to remove the CO~2~ release pure CO~2~ or a
    CO~2~/SO~2~ stream upon regeneration. Typically, the carbon dioxide
    that is removed from the gas is vented to the atmosphere. If the
    carbon dioxide is captured, certain amounts of methane (up to 5%)
    may also remain in the captured gas and will be stored with the
    carbon dioxide.

-   *Cement manufacture.* Pure carbon dioxide is emitted when limestone
    (calcium carbonate, CaCO~3~) is heated to form clinker (calcium
    oxide (or lime), CaO).

-   *Ammonia production.* Steam reforming converts methane (CH~4~) to
    hydrogen (H~2~) and carbon dioxide. The hydrogen is reacted with
    nitrogen (N~2~) to make ammonia (NH~3~). Chemical or physical
    absorbents used to facilitate this process release pure CO~2~ or a
    CO~2~/SO~2~ stream upon regeneration.

-   *Hydrogen manufacture.* Light hydrocarbons are reacted with steam to
    form a mixture of hydrogen and carbon dioxide. Carbon dioxide is
    separated from the hydrogen product and a highly concentrated stream
    of carbon dioxide is released.

-   *Ethanol manufacture.* Biogenic carbon dioxide is produced and
    vented during corn fermentation.

-   *Helium production.* Carbon dioxide accounts for up to 90 percent of
    the gas found in certain helium reservoirs. Helium and carbon
    dioxide must be separated prior to helium use.

-   *Advanced coal-fired power generation.* Integrated gasification
    combined cycle (IGCC) power plants emit a sequestration-ready[^165]
    stream of carbon dioxide, as would FutureGen-type[^166] plants which
    produce both electricity and hydrogen.

+--------------------------------------------+----------+--------------+---+
| ####                                       |          |              |   |
| ## Table 1.G.1. Current High-Concentration |          |              |   |
|  Carbon Dioxide Vents in the United States |          |              |   |
+--------------------------------------------+----------+--------------+---+
| **Type of CO~2~ Vent**                     | **Number | **Aggregate  |   |
|                                            | of Vents | CO~2~**      |   |
|                                            | in the   | **Emissions  |   |
|                                            | U.S. in  | in 2000**    |   |
|                                            | 2000**   |              |   |
|                                            |          | **(          |   |
|                                            |          | MMmtCO~2~)** |   |
+--------------------------------------------+----------+--------------+---+
| Oxygen-blown gasification                  | 11       | 55 ^1^       |   |
+--------------------------------------------+----------+--------------+---+
| Natural gas processing                     | 580      | 55 ^2^       |   |
+--------------------------------------------+----------+--------------+---+
| Cement manufacture                         | 37       | 40.3 ^3^     |   |
+--------------------------------------------+----------+--------------+---+
| Ammonia production                         | 40       | 16.1 ^4^     |   |
+--------------------------------------------+----------+--------------+---+
| Hydrogen manufacture                       | 40       | 13.9 ^5^     |   |
+--------------------------------------------+----------+--------------+---+
| Ethanol manufacturer                       | 40       | 4.4 ^6^      |   |
+--------------------------------------------+----------+--------------+---+
| Helium production                          | none     | 0            |   |
+--------------------------------------------+----------+--------------+---+
| Advanced coal-fired power generation       | none     | 0            |   |
+--------------------------------------------+----------+--------------+---+
| **Total**                                  |          | **184.7**    |   |
+--------------------------------------------+----------+--------------+---+
| ^1^ SFA Pacific/Gasification Technologies  |          |              |   |
| Council, Gasification Database, 2001.      |          |              |   |
|                                            |          |              |   |
| ^2^ Combined EIA estimate for emissions    |          |              |   |
| from natural gas processing (Emissions of  |          |              |   |
| GHGs in the U.S. 2000, Table 4) with       |          |              |   |
| emissions from selected large volume point |          |              |   |
| sources supplied by API. Number of vents   |          |              |   |
| is from the Natural Gas Supply Association |          |              |   |
| (2005).                                    |          |              |   |
|                                            |          |              |   |
| ^3^ EPA Inventory of U.S. GHG Emissions    |          |              |   |
| and Sinks, 2002, Emission Factor           |          |              |   |
| Documentation AP-42, Section 11.6.         |          |              |   |
|                                            |          |              |   |
| ^4^ EPA Inventory of U.S. GHG Emissions    |          |              |   |
| and Sinks, 2002, Emission Factor           |          |              |   |
| Documentation AP-42, Section 5.2; Twenty   |          |              |   |
| sources of less than 0.02 MMmtC/yr were    |          |              |   |
| omitted.                                   |          |              |   |
|                                            |          |              |   |
| ^5^ Refinery Capacity Data as of January   |          |              |   |
| 1, 2001. Database file "RefCap01.dpf,"     |          |              |   |
| Energy Information Administration (EIA),   |          |              |   |
| Form EIA-820, "Annual Refinery Report";    |          |              |   |
| 3,243 MMSCFD H~2~ production capacity      |          |              |   |
| converted to CO~2~ using the factor 0.26   |          |              |   |
| scf highly pure CO~2~ vented per scf H~2~  |          |              |   |
| produced; 24 sources of less than 0.02     |          |              |   |
| MMmtC/yr were omitted.                     |          |              |   |
|                                            |          |              |   |
| ^6^ Renewable Fuels Association web site,  |          |              |   |
| 1.63 billion gallons of ethanol produced   |          |              |   |
| in 2001; conversion factor, 3 kg CO~2~ per |          |              |   |
| gallon ethanol from Kansas Geological      |          |              |   |
| Survey; 35 sources of less than 0.02       |          |              |   |
| MMmtC/yr were omitted. Note that carbon    |          |              |   |
| dioxide from biomass fermentation or       |          |              |   |
| combustion would be considered biogenic,   |          |              |   |
| and would not contribute to total reported |          |              |   |
| emissions under the Voluntary Reporting    |          |              |   |
| Program or national inventories. However,  |          |              |   |
| sequestration of biogenic carbon would be  |          |              |   |
| considered a "negative emission."          |          |              |   |
+--------------------------------------------+----------+--------------+---+

#### 1.G.3 Accounting for Sequestered Carbon Dioxide Over Time

When carbon dioxide is injected into a geologic formation, it is
expected that it will be sequestered permanently, barring any physical
disruption of the reservoir or injection wells.

When a geologic sequestration project is undertaken for the sole purpose
of emissions mitigation, the accounting is straightforward. The amount
of carbon dioxide emitted may be determined as the quantity of carbon
dioxide lost as fugitive emissions during the capture, transport, and
injection of carbon dioxide. Once injection of the captured carbon
dioxide is completed and the wells are sealed, the reporter will be
responsible for any potential physical leakage of carbon dioxide
occurring every year thereafter. The reporter should use one of the
following two methods for determining post-injection physical leakage:

a)  Actively monitor and maintain the site, measuring actual carbon
    dioxide losses from the well heads and the storage reservoir, which
    would then be treated as emissions in the year in which they occur.
    Section 1.G.7 describes methods for tracking post-injection leakage.

b)  Apply a site-specific monitoring plan already approved by a relevant
    Federal or state regulatory agency for the purpose of tracking
    carbon dioxide seepage/leakage.

If the entity chooses not to monitor the storage site for any potential
post-injection physical leakage, it must assume that the entire stock of
carbon dioxide will be reemitted to the atmosphere, and include this
emission in the reporter's inventory for that year.

Use of carbon dioxide for enhanced resource recovery presents a special
case in evaluating the amount of carbon dioxide released over time.
Sources that should be counted towards the inventory include the amount
of carbon dioxide released during injection, extraction and
re-injection, and the amount released after the project has ended.

Emissions reporting responsibilities are the same as for any other
geologic sequestration project; while enhanced recovery operations are
underway, the reporter must determine fugitive losses of carbon dioxide
each year. When enhanced resource recovery operations are concluded, and
each year thereafter, the reporter must determine any physical leakage
using one of the two methods outlined above. If the entity decides not
to monitor post-injection leakage, it must include the entire stock of
injected carbon dioxide in the inventory for that year.

#### 1.G.4 Accounting Protocols for Geologic Sequestration Activities

As discussed in Section 1.G.2, above, several tools exist for reporters
to estimate their greenhouse gas emissions. The IPCC Special Report on
Carbon Dioxide Capture and Storage includes a chapter on issues related
to emissions inventories and accounting that may be useful to reporters.
Existing protocols for other industries may also be utilized. While not
written with carbon dioxide sequestration in mind, these estimation
methodologies may provide guidance in calculating emissions from various
aspects of geologic sequestration, including transportation, handling,
and fugitive emissions. For example, the California Climate Registry
recommends reviewing relevant methodologies and/or calculations with
technical assistance providers or other environmental experts, and
refers to several resources for reporters to develop a means of
estimating fugitive emissions from natural gas transport and
distribution, and coal mining.[^167]

The following subsections summarize existing protocols for estimating
emissions from these various aspects of geologic sequestration projects:

-   Fugitive emissions from the processing, transport, injection, and
    withdrawal of carbon dioxide;

-   Direct and indirect emissions from increased energy use resulting
    from sequestration; and

-   Post-injection seepage of carbon dioxide to the atmosphere.

For each type of carbon sequestration project, measurement-based methods
available to reporters are explained, as well as calculation-based
protocols, if available. As in previous Parts of these Technical
Guidelines, each methodology is rated. In all cases, continuous
emissions monitoring and mass balance calculations based on measured
emissions data are rated "A." At this time, standard emissions factors
for the capture, transport, and injection of carbon dioxide have not
been developed. If developed in the future and approved by DOE, these
factors would be appropriate to use for a "B" or "C" rating.

#### 1.G.5 Fugitive Carbon Dioxide Emissions

This section explains how to estimate the amount of carbon dioxide lost
to the atmosphere during the capture, processing, transport, injection,
and extraction of carbon dioxide. This includes a discussion of fugitive
emissions from the production of carbon dioxide both from naturally
occurring reservoirs and from the waste stream processes associated with
power generation and industrial processes. In the case of ERR,
particularly EOR, naturally occurring carbon dioxide is more commonly
used, but a few projects also use carbon dioxide captured from
industrial processes or natural gas processing. It is unlikely that
naturally occurring carbon dioxide would be harvested for any other
purposes than enhanced resource recovery activities. Carbon dioxide
produced as a byproduct of industrial processes and power generation
could be sequestered via enhanced resource recovery practices, as well
as in saline formations.

##### 1.G.5.1 Fugitive Emissions from the Extraction of Naturally Occurring Carbon Dioxide 

Reporters could use existing monitoring techniques, such as flow meters,
to measure the amount of carbon dioxide lost from the natural geologic
reservoirs, combined with periodic (at least annual) analyses of gas
composition to determine the carbon dioxide content. This approach would
be rated "A."

Calculating the fugitive emissions from a natural reservoir using a mass
balance method based on the difference of measurements of the carbon
dioxide contained in the reservoir before and after withdrawal, minus
the amount extracted, (Equation 1) is rated "B."

[]{.mark}

**E~fug~ = C~1~ -- C~2~ -- C~3~ (1)**

[]{.mark}

**Where:**

**E~fug~ = Amount of fugitive CO~2~ from the geologic reservoir**

> **C~1~** **= Amount of measured CO~2~ contained in the reservoir
> before extraction**

**C~2~** **= Amount of measured CO~2~ contained in the reservoir after
extraction**

**C~3~ = Amount of measured CO2 extracted from the geologic reservoir**

##### 1.G.5.2 Fugitive Emissions from the Extraction of Carbon Dioxide from Anthropogenic Sources

There are several industrial and energy combustion processes that emit a
relatively concentrated stream of carbon dioxide that is suitable for
use in geologic sequestration. These sources, as described above, are
oxygen-blown gasification, natural gas reprocessing, cement manufacture,
ammonia production, steam reforming in an oil refinery, ethanol
manufacture, helium production, and advanced coal-fired power
generation. Reporters should refer to Parts C and E of this Chapter of
the Technical Guidelines for a discussion and rating of methods for
estimating carbon dioxide produced from each of these sources.

Not all carbon dioxide is collected during the capture process; some
will instead be released to the atmosphere. Arriving at the correct
inventory of emissions after capture may involve some subtractions to
determine the correct amount of carbon dioxide emitted. Estimation
methods based on continuous emissions monitoring will automatically
reflect the amount captured and emitted while mass balance approaches
based on the amount of fuel combusted will have to be adjusted for the
amount captured. The following estimation methods can be used for
determining the amount of carbon dioxide that remains in the waste
stream if the reporter is not using a continuous emissions monitoring
system to determine carbon dioxide emissions.

Calculating the difference in the direct measurements of carbon dioxide
emitted from the emissions source, downstream from the capture
technology and upstream from the capture technology, will yield the net
carbon dioxide released to the atmosphere (Equation 2). This method of
mass balance merits an "A" if the calculation is based on continuous
emissions monitoring or flow meter data. It rates a "B" if based on
annual emissions data.

**E~cap~ = E~upstream~ -- E~downstream~** **(2)**

**Where:**

**E~cap~ = Fugitive CO~2~ emissions during the capture process**

> **E~upstream~ = Direct measurement of CO~2~ in emissions stream
> upstream from capture technology**
>
> **E~downstream~ = Direct measurement of CO~2~ in emissions stream
> downstream from capture technology.**

Calculation of carbon dioxide emissions may be estimated based on the
manufacturer's specifications for the carbon dioxide capture technology
(Equation 3). This method is rated "C" because there are no real
measurements of carbon dioxide emissions captured.

**E~cap~ = (1 --**$\eta$**)E~s~ (3)**

**Where:**

**E~cap~ = Fugitive CO~2~ emissions during the capture process**

$\eta$ **= Published efficiency of CO~2~ capture technology**

**E~s~ = Emissions from source, without capture process**

##### 1.G.5.3 Fugitive Emissions from Transport and Processing

Transportation of carbon dioxide from the source to the injection site
may result in some leakage to the atmosphere. Carbon dioxide may be
transported by tank or pipeline, and due to material weaknesses of the
system, some carbon dioxide may be released during this process. If the
carbon dioxide is transported by tank or aboard a truck, ship, or other
vehicle, reporters must determine the additional emissions from
vehicular transport. For instructions on reporting emissions from the
mobile sources themselves, the reporter should refer to Part D on
transportation.

There are several options available to reporters to quantify the amount
of carbon dioxide lost during transport.

Calculating the difference in the amount of carbon dioxide traveling
between points in pipeline transit (Equation 4) is rated "A" for
determining the amount of carbon dioxide lost to the atmosphere. Flow
meters should be set up to measure the amount of gas supplied to the
pipeline at the source and at the endpoint of the pipeline. The effect
of differences in the surrounding temperatures at the beginning and
endpoint would also need to be taken into account to adjust volumetric
values according to cooler or warmer climates.

**E~trans~ = C~in~ -- C~out~ (4)**

**Where:**

**E~trans~ = Fugitive CO~2~ emissions from transportation via pipeline**

> **C~in~ = Direct measurement of CO~2~ at pipeline input**
>
> **C~out~** **= Direct measurement of CO~2~ at pipeline endpoint**

Calculating the difference in the amount of carbon dioxide contained in
a tank (Equation 5), based on a measurement taken at the time the tank
is filled and a measurement taken at the point the tank is delivered to
the injection site, to determine the amount of carbon dioxide lost to
the atmosphere (Equation 5), is also rated "A."

**E~trans~ = C~fill~ -- C~del~ (5)**

**Where:**

**E~trans~ = Fugitive CO~2~ emissions from transportation via tank**

> **C~fill~ = Direct measurement of CO~2~ at source, filling of tank**
>
> **C~del~** **= Direct measurement of CO~2~ at pipeline, delivery of
> tank**

Calculating the difference in the amount of carbon dioxide traveling
between points in pipeline transit is rated "B" if determined by annual
measurements of carbon dioxide in the pipeline at the place of capture
or extraction and the point of injection.

Calculating the difference in the estimated amounts of carbon dioxide
sent to the pipeline and taken out of the pipeline will yield the amount
of carbon dioxide lost. The amount of carbon dioxide input into the
pipeline may be estimated by the manufacturer specifications for carbon
dioxide capture technology efficiency (Equation 3, above). The amount of
carbon dioxide output by the pipeline may be estimated to be the amount
of carbon dioxide injected for ERR. This case of estimating the amount
of carbon dioxide emissions from pipeline transportation without
measuring any carbon dioxide quantities (Equation 6) is rated "C."

**E~trans~ = E~cap~ -- C~req~ (6)**

**Where:**

**E~trans~ = Fugitive CO~2~ emissions from transportation via pipeline**

**E~cap~** **= Estimation of CO~2~ capture based on Equation 3, above**

**C~req~** **= Amount of CO~2~ injected for enhanced resource recovery**

Estimating fugitive emissions from carbon dioxide pipelines may also be
accomplished by using average emission factors. Table 1.G.2 presents
average carbon dioxide emission factors from pipelines and processing
equipment. These emission factors are based on industry guidance for
estimating fugitive losses from natural gas pipelines, and have been
adjusted to represent emissions from carbon dioxide pipelines. The
underlying natural gas emission factors are provided inhfae API
*Compendium of Greenhouse Gas Emissions Estimation Methodologies for the
Oil and Gas Industry* to e and the Interstate Natural Gas Association of
America (INGAA) *Greenhouse Gas Emission Estimation Guidelines for
Natural Gas Transmission and Storage: Volume 1 -- GHG Emission
Estimation Methodologies and Procedures*.. The Tier 1 emission factors
only require information on pipeline length while the Tier 2 emission
factors require information on pipeline length and processing equipment.
Either method can be used.

###### Table 1.G.2. Emission Factors for Fugitive Emissions from Transport and Processing

+---------------+------------+------------+-----------+--------------+
| **Segment**   | **Activity | **GHG**    | **EF**    | **EF Units** |
|               | Data By    |            |           |              |
|               | C          |            |           |              |
|               | omponent** |            |           |              |
+---------------+------------+------------+-----------+--------------+
| ###           |            |            |           |              |
| ###### Tier 1 |            |            |           |              |
+---------------+------------+------------+-----------+--------------+
| Transmission  | Pipeline   | CO~2~^1^   | 22,168.25 | lb           |
|               | length     |            |           | CO~          |
|               |            |            |           | 2~/mile-year |
+---------------+------------+------------+-----------+--------------+
| Tier 2        |            |            |           |              |
+---------------+------------+------------+-----------+--------------+
| Transmission  | Compressor | CO~2~^1^   | 3,455,482 | lb           |
|               | station    |            |           | CO~2~/       |
|               | count      |            |           | station-year |
+---------------+------------+------------+-----------+--------------+
| Transmission  | Meter      | CO~2~^1^   | 6,951.15  | lb           |
|               | /Regulator |            |           | CO~2~/       |
|               | station    |            |           | station-year |
|               | count      |            |           |              |
+---------------+------------+------------+-----------+--------------+
| Transmission  | Pipeline   | CO~2~^1^   | 72.20     | lb           |
|               | length     |            |           | CO~          |
|               |            |            |           | 2~/mile-year |
+---------------+------------+------------+-----------+--------------+

^1^The carbon dioxide emission factors were derived by converting
natural gas-based carbon dioxide pipeline and equipment leak emission
factors to pure carbon dioxide-based emission factors. The natural
gas-based emission factors were obtained from Tables 4-2 and Table 4-3
of the Interstate Natural Gas Association of America (INGAA) Greenhouse
Gas Emission Estimation Guidelines for Natural Gas Transmission and
Storage: Volume 1 -- GHG Emission Estimation Methodologies and
Procedures. Tables 4-2 and 4-3 assume that 2% carbon dioxide is
entrained in the natural gas. In the case of engineered sequestration we
assume that 95% of the gas transported in the pipeline is carbon
dioxide. Therefore, to convert the emission factors we divided by two
and multiplied by 95.

Table Source: Interstate Natural Gas Association of America (INGAA)
Greenhouse Gas Emission Estimation Guidelines for Natural Gas
Transmission and Storage: Volume 1 -- GHG Emission Estimation
Methodologies and Procedures. September 28, 2005; and American Petroleum
Institute, Compendium of Greenhouse Gas Emissions Estimation
Methodologies for the Oil and Gas Industry, February 2004.

Fugitive carbon dioxide emissions can be derived by applying Equation 7
and inserting the average emissions factors supplied in Table 1.G.2.
Because the emissions factors are based on natural gas instead of carbon
dioxide pipelines the emission factors may overstate fugitive emissions.
However, at this time, there is insufficient data to develop average
emission factors specifically for carbon dioxide pipelines. The use of
this method is rated "D."

  ----------------------- ----------------------- -----------------------
                                                  

                                                  

                                                  

                                                  

                                                  

                                                  

                                                  

                                                  
  ----------------------- ----------------------- -----------------------

The API

**E~trans~ = ∑** **EF~i~ \* i (7)**[^168]

**Summation of EF~i~** **for all i component types**

**Where:**

**E~trans~ = Fugitive CO~2~ emissions from pipeline transport**

**EF~i~** **= Average emission factor for component, i**

**i = Pipeline and/or processing** **component** **(miles and/or station
count)**

##### 1.G.5.4 Fugitive Emissions from Injection and Extraction for Enhanced Resource Recovery (ERR)

Many enhanced resource recovery operations recycle carbon dioxide used
in the recovery process by re-injecting it into the same well or
transferring it to a new recovery site. Some carbon dioxide might be
lost to the atmosphere during this process of recycling; it may be
emitted when injected or when extracted. The following subsections
describe how to account for any potential fugitive emissions from the
recycling of carbon dioxide for enhanced resource recovery.

Use of a monitoring system to measure the loss of carbon dioxide during
recycling is rated "A."

Calculating the amount of carbon dioxide lost during the reporting
period as the difference between the amount of carbon dioxide needed for
enhanced resource recovery and the estimated amount of carbon dioxide
stored is rated "D" (Equation 8). In this case, no measurements are
made, but rather, amounts of carbon dioxide in storage and used for ERR
are based on historical data and process needs, respectively.

**E~rec~ = C~store~ -- C~req~ (8)**

**Where:**

**E~rec~ = Emissions during recycling of CO~2~ from storage**

**C~store~** **= Amount of CO~2~ in storage at the beginning of the
reporting period**

**C~req~** **= Amount of CO~2~ required for ERR during the reporting
period**

#### 1.G.6 Direct and Indirect Emissions

##### 1.G.6.1 Energy Used for the Carbon Dioxide Capture Process

Energy is used in all stages of carbon dioxide capture and geologic
sequestration. For example, the energy used to capture carbon dioxide in
a coal-fired plant lowers the plant's net energy output because
additional energy is required to power the capturing equipment. In the
case of a manufacturing plant, the additional energy requirement for
carbon dioxide capture increases the plant's direct and indirect carbon
dioxide emissions from fossil fuel combustion. Another potential
emission source includes the fuel used for compressing captured carbon
dioxide to the properties of pipeline gas. Reporters should refer to
Parts C and F, which provide guidance on reporting emissions from onsite
electricity generation and/or indirect emissions from offsite
electricity generation, respectively, for further discussion.

##### 1.G.6.2 Energy Used for the Carbon Dioxide Injection Process

Carbon dioxide injection requires energy to operate the compression and
injection equipment. This additional energy could be generated onsite or
offsite. The changes in emission levels due to increased direct and
indirect energy use will be addressed when an entity accounts for its
overall emissions from stationary combustion and purchase of
electricity/heat from indirect sources. Reporters should refer to Parts
C and F for more detailed guidance on measuring or calculating emissions
from stationary combustion and estimating indirect emissions from
offsite electricity and heat generation.

Not all injection equipment will be powered by electricity; some
equipment might be fueled by natural gas, fuel oil, propane, or another
fuel. In this case, direct monitoring is a possibility, as is
determining emissions based on the known energy use and efficiency of
the equipment. Reporters should refer to Part C for protocols to
calculate emissions from fuel combustion.

##### 1.G.6.3 Energy Used for Extraction for Enhanced Resource Recovery (ERR)

The production of oil resulting from ERR requires considerable energy
for pumping additional fluids, power boilers, gas compression and
dehydration, and re-injection and recycling of carbon dioxide. Similar
to the energy use for the injection process, the changes in emission
levels due to increased direct and indirect energy use during ERR will
be addressed when an entity accounts for its overall emissions from
stationary combustion and purchase of electricity/heat from indirect
sources. Reporters should refer to Parts C and F for more detailed
guidance on measuring or calculating emissions from stationary
combustion and estimating indirect emissions from offsite electricity
and heat generation.

Not all ERR production and re-injection equipment will be powered by
electricity; some equipment might be fueled by natural gas, fuel oil,
propane, or another fuel. In this case, direct monitoring is a
possibility, as is determining emissions based on the known energy use
and efficiency of the equipment. Reporters should refer to Part C for
protocols to calculate emissions from fuel combustion.

#### 1.G.7 Post-Injection Seepage of Carbon Dioxide to the Atmosphere

Monitoring at current carbon dioxide storage sites indicates that
physical leakage rates of carbon dioxide are very small or nonexistent
for geologic formations, when they are chosen with care. However, this
does not prevent any seepage of carbon dioxide from occurring in the
future and entities are responsible for monitoring and reporting such
seepage during the reporting year that the emissions occur.

Many options are available to estimate the amount of carbon dioxide
released from permanent geologic formations over time. Many of these
methods are still being tested for effectiveness, uncertainty, and cost.
The review of these methods is a rapidly evolving area of study.As a
reneral, available methods for monitoring stored carbon dioxide focus on
two areas: 1) monitoring of lateral reservoir migration of carbon
dioxide over time to assess the integrity of the storage reservoir; and
2) monitoring of carbon dioxide leakage outside of the reservoir and
eventually to surface due to vertical migration. Examples of each type
of monitoring method are provided below, with some techniques fitting
into both areas.[^169] Current capture and storage projects, such as the
Weyburn EOR project in Saskatchewan, Canada, typically use a combination
of these two monitoring types. A monitoring plan that uses 4D seismic
surveys, reservoir pressure monitoring, formation fluid monitoring,
shallow water sampling (if present), and soil gas surveys is rated A. A
monitoring plan that includes periodic (at least annual) monitoring
using one or more direct measurement techniques in each of the two areas
is rated B. A monitoring plan that relies on measurement techniques in
only one area is rated C. In addition to the monitoring methods outlined
above, reporters may also use a monitoring plan that has already been
approved by a relevant Federal or state regulatory agency for the
purpose of tracking carbon dioxide seepage/leakage. Use of such a method
is rated B.

Monitoring plan time frames and long term liability are not addressed by
these guidelines and will vary according to specific circumstances.

Area 1: Monitoring techniques for tracking lateral migration of carbon
dioxide:

-   *Seismic surveys*: 2D, 3D, wellbore-to--surface, and cross-wellbore
    seismic surveys are sometimes employed in the site characterization
    process, but can also be effective in identifying the location of
    the injected carbon dioxide in the reservoir.

-   *Gravimetric measurements*: Gravimetric measurements can be used to
    locate carbon dioxide already injected in the reservoir.

-   *Wellhead and formation fluid sampling*: Periodic fluid sampling can
    be used to verify where the carbon dioxide is in the formation.

Area 2: Monitoring techniques for tracking carbon dioxide leakage
outside the reservoir:

-   *Radioisotope tracer monitoring of cement integrity*: The casings of
    injection wells are known to be the most vulnerable spot for leaks.
    Periodic measurements of cement integrity with gamma-ray tools have
    been shown to be effective in detecting and preventing leakage.

-   *Seismic surveys*: repeat 3D (i.e.4D) seismic surveys can be used to
    detect leakage out of the reservoir as well as determine the lateral
    extent of the carbon dioxide in the reservoir.

-   *Reservoir pressure monitoring*: Careful logging of reservoir
    pressures will allow for detection of any carbon dioxide migration
    outside the injection reservoir. (Note: this technique may not be
    applicable to storage in saline aquifers.)

-   *Establishment of monitoring wells*: Dedicated monitoring wells can
    be employed for measurement of reservoir pressure and sampling for
    direct detection of carbon dioxide or tracers.

-   *Microseismic monitoring of rock response to injection*: Monitoring
    of seismic activity during and after injection can predict potential
    seepage to the atmosphere.

-   *Use of natural or induced tracers*: Radioisotope tracers can be
    injected into the formation along with the carbon dioxide, giving it
    a "signature" and allowing for easy detection of any carbon dioxide
    that migrates outside the injection reservoir.

-   *Water sampling for carbon speciation and stable isotopes*: Periodic
    sampling of water in overlying aquifers can be used to verify that
    the carbon dioxide has remained in the injection reservoir.

-   *Fracture analysis and flow simulations*: Simulations are often used
    as part of the site characterization process, but can also be
    powerful tools for leak prevention.

-   *Ecosystem impact analyses*: Soil gas surveys, detailed observations
    of plant communities, ground water quality analysis and other
    techniques can be used to detect any signals that carbon dioxide has
    seeped from the reservoir.

The ratings for the various methods for measuring and estimating carbon
dioxide emissions related to geologic sequestration are summarized in
Table 1.G.3.

###### Table 1.G.3. Summary of Ratings for Geologic Sequestration of Carbon Dioxide

  ----------------------------------------------------- -----------------
  **Item**                                              **Rating**

  **Fugitive Emissions from the Extraction of Naturally 
  Occurring CO~2~**                                     

  Direct measurement and at least annual content        A
  analysis of gas                                       

  Mass balance based on before-and-after measurements,  B
  minus amount extracted *(Equation 1)*                 

  **Fugitive Emissions During the Extraction of CO~2~   
  from Anthropogenic Sources**                          

  Difference between upstream and downstream            A
  measurements based on CEM or flow meter data          
  *(Equation 2)*                                        

  Difference between upstream and downstream            B
  measurements based on annual emissions data           
  *(Equation 2)*                                        

  Manufacturer's specifications for capture technology  C
  employed *(Equation 3)*                               

  **Fugitive Emissions During Transport and             
  Processing**                                          

  Direct actual measurements at pipeline beginning and  A
  endpoint *(Equation 4)*                               

  Direct actual measurements at tank fill and delivery  A
  *(Equation 5)*                                        

  Annual measurements at pipeline beginning and         B
  endpoint *(Equation 4)*                               

  Estimating without direct measurement *(Equation 6)*  C

  Use of EPA VOC emissions factors *(Equation 7)*       D

  **Fugitive Emissions of CO~2~ During Injection and    
  Extraction for Enhanced Resource Recovery**           

  Monitoring system for direct CO~2~ loss measurement   A

  Difference in CO~2~ needed and CO~2~ stored           D
  *(Equation 8)*                                        

  **Post-Injection Seepage of Carbon Dioxide to the     
  Atmosphere**                                          

  Monitoring plan using 4D seismic, reservoir pressure  A
  monitoring, formation fluid monitoring, shallow water 
  sampling (if present) and soil gas surveys            

  Monitoring plan using one or more measurement         B
  techniques in both categories                         

  Federal or state approved monitoring plan             B

  Monitoring plan using measurement techniques in only  C
  one category                                          
  ----------------------------------------------------- -----------------

**Technical Guidelines for Voluntary Reporting of Greenhouse Gases
Program**

**Chapter 1, Emission Inventories**

### Part H: Agricultural Emissions and Sequestration

Outline

1\. Introduction

2\. Emissions Sources and Sinks

3\. Estimation Methods

3.1. Direct Measurement

3.2. Process Models

3.3. Inference

> 3.4 Hybrid Estimation Approaches\
> 3.5 Rating Scale for Estimation Methods
>
> 4\. Category-Specific Estimation Guidance

4.1. Livestock Sources

> 4.1.1. Characterizing Animal Populations and Climate Regions\
> 4.1.2. Enteric Fermentation
>
> 4.1.3. Livestock Waste

4.2. Crop Production Sources

> 4.2.1. Residue Burning\
> 4.2.2. Rice Cultivation\
> 4.2.3. Nitrous Oxide from Agricultural Soils
>
> 4.2.4. Lime Applications

4.3. Agricultural Soil Carbon Emissions and Sequestration

> 4.3.1. Characterizing the Land Base
>
> 4.3.2. CO~2~ Fluxes on Mineral Soil
>
> 4.3.3. CO~2~ Emissions on Cultivated Organic Soils

**Technical Guidelines Chapter 1, Part H: Agricultural Emissions and
Sequestration**

#### 1.H.1 Overview 

This section supports and supplements the General Guidelines for
reporting greenhouse gas information under Section 1605(b) of the Energy
Policy Act of 1992 (EPAct). The General Guidelines provide the rationale
for the Voluntary Reporting of Greenhouse Gases Program and overall
concepts and methods to be used in reporting. The reader should be
familiar with the contents of the General Guidelines and Chapter 1 Part
A of the Technical Guidelines before proceeding to the specific guidance
in this Part on the agricultural sector's methods and data requirements.
Other Parts in this Chapter address the sectors of electricity,
residential and commercial buildings, industry, transportation, and
forestry.

This Voluntary Reporting of Greenhouse Gases Program has been designed
to be flexible, and includes a variety of methods for making estimates
of emissions and sequestration. The methods range from simple and
inexpensive to complex and costly, and reporters may choose the simplest
methods that provide estimates with an accuracy that meets reporting
objectives. For example, "default" emission and sequestration factors
are provided for those who wish to report using data that are typical
for agricultural activities in a region, but may not represent a
specific entity. Guidance is provided for developing methods that are
more specific to an entity, including approaches that allow reporters to
calculate a known accuracy. The default factors that this document
provides can be used to convert existing data directly into estimated
quantities of emissions or sequestration. The intent of the default
emission and sequestration factors is to simplify the reporting process,
not to discourage reporters from developing their own emissions
estimates.

This section provides guidance on identifying and quantifying emissions
and sequestration from agricultural sources and sinks. Throughout this
section, reference is made to the Practice Standards and Specifications
of the U.S. Department of Agriculture's (USDA) Natural Resources
Conservation Service (NRCS). Each practice referenced has a national
standard and local specifications designed to ensure quality standards.
Practice standards and specifications are available in the Field Office
Technical Guide, available at the NRCS website:
[www.nrcs.usda.gov/technical/efotg/](http://www.nrcs.usda.gov/technical/efotg/).
All emission reductions or sequestration reported should be consistent
with applicable conservation treatment of the land.

#### 1.H.2 Emission Sources and Sinks 

Greenhouse gas (GHG) emissions may occur from livestock and/or crop
production. GHG source categories from livestock include enteric
fermentation and livestock waste,[^170] and from crop production include
residue burning, rice cultivation, nutrient applications, and lime
applications. Crop production and grazing land management can also be a
source or sink of carbon dioxide (CO~2~): the oxidation of organic
matter in soil causes carbon dioxide emissions from soils. Land
management practices including tillage, rotations, fallowing, and cover
crops influence the rates of organic soil matter oxidation. Carbon
sequestration occurs when management practices increase the amount of
organic carbon contained in soil and/or promote growth of long-lived
perennial biomass (e.g., trees and permanent grasses).

The methods described below can be used to develop emissions estimates
for each of the livestock and crop production sources described above.
Methods are also provided for estimating carbon flux in soils. For each
source and sink category, guidance is provided for at least one method,
and where possible, additional methods for estimating emissions and
carbon flux are explained. In addition, explanations of the
uncertainties associated with each estimation methodology are provided
to assist in providing assessments of its relative reliability. Finally,
estimation method ratings are given on an ordinal scale; the recommended
method is the best that is currently available even though it may be
relatively uncertain. The estimation method ratings can be used to
calculate entity scores following guidance provided in Part A of this
Chapter.

#### 1.H.3 Estimation Methods 

There are several different approaches to estimating greenhouse gas
emissions and carbon sequestration in agricultural operations. Because
agricultural emissions and sequestration occur over relatively large
geographic areas and, for many farm activities and land use decisions,
vary in magnitude depending on specific conditions, they are often
difficult to measure directly. In many cases, the most reliable and
cost-effective methods are a combination of point sampling with a
statistically derived expansion factor. This approach allows for the
calculation of a standard error as an estimate of certainty. In some
cases, even point scale measurement is prohibitively expensive and the
most cost effective means of estimation is through the use of
site-specific inputs, such as acres and number of head of livestock, and
default equations.

##### 1.H.3.1 Direct Measurement 

The most accurate way to estimate GHG emissions and carbon flux is
through continuous direct measurement. Direct measurement uses special
instruments that monitor the flow of gases from the source into the
atmosphere. Many, but not all, GHG emissions sources in agriculture can
be measured with such instrumentation. For example, techniques exist to
measure methane (CH~4~) emissions from enteric fermentation in
livestock, including controlled livestock chambers and pastures fitted
with gas flux towers. Flux chambers can also be used to monitor the
amount of nitrous oxide (N~2~O) and/or carbon dioxide gas emitted from a
small plot of land, metering the products of nitrogen and carbon cycles.
Emissions from livestock waste can be readily monitored in certain
circumstances, (e.g., covered anaerobic lagoons fit with gas flux
meters), although where waste is not managed in a confined system (e.g.,
manure deposited directly in pasture, range, or paddock), it is
difficult if not impossible to directly measure emissions. Techniques
for continuous or periodic direct measurement of GHG emissions are
practical and necessary when conducting research and may be incorporated
into large scale projects as a means of developing more site specific
emission factors.

At the farm level, continuous direct measurement of GHG emissions is
often costly and therefore not feasible. Direct measurement techniques,
however, can be used to sample emission sources and derive data to
improve more approximate estimation techniques such as those described
below. The resulting hybrid designs may provide reasonable accuracy and
feasibility.

Carbon flux over a large land area is virtually impossible to measure
directly, although net fluxes in soil carbon can be closely approximated
by directly measuring the carbon content of soils over time. Net carbon
fluxes (either positive or negative) are inferred as the change in
carbon stocks over time.

##### 1.H.3.2 Process Models 

Models that estimate ecosystem processes, such as the nitrogen and
carbon cycles, are becoming increasingly available. Process models
typically rely on a series of input data that research has shown to be
important drivers of the process being modeled. These models may be
mathematically simple or complex depending on the nature of the process.
In some instances only a few inputs are needed to estimate the outputs
of a process; in others, multiple inputs over different spatial and
temporal scales are required. Input data can be physical variables such
as temperature, precipitation, elevation, and soil nutrient levels, or
biological variables such as soil microbial activity and plant
diversity.

The accuracy of process models is variable and depends on the robustness
of the model and the accuracy of the inputs. Model robustness can be
empirically determined through validation where projected outputs are
compared to direct measures. The decision to use process models will
depend on the resources available and the existence of appropriate
models or the tools to develop a reporter's own models.

##### 1.H.3.3 Inference 

The simplest estimation methods are what these guidelines refer to as
"inferences." The inference approach relies on input data multiplied by
State, regional, or national emissions/sequestration factors that
approximate emissions/sequestration per unit of the input. For example,
to obtain an entity-level estimate of CH~4~ emissions from enteric
fermentation, emissions may be estimated by multiplying the number of
dairy cattle the entity owns by an emission factor that reflects how
much CH~4~ is emitted per head of dairy cattle.

The accuracy of inference approaches varies depending on the specificity
of the emission factor applied and the accuracy of the input data.
Factors used to estimate emission and sequestration sources and sinks in
agriculture rarely capture the full complexity of underlying biological
processes, which are driven by a number of external variables such as
climate, soil conditions, livestock diet, and livestock genetics. An
inference approach thus generally yields estimates that are less
accurate than those developed using site-specific approaches, although
the estimates can be improved by using the most specific emissions
factors available (i.e., matched to the climate region, livestock
category, soil type, etc.).

The accuracy of the inference approach also depends on the inherent
variability of the sources being estimated. For some agricultural
sources, regional or national emission factors provide emissions
estimates with relatively low uncertainty, while for other sources
emission estimates will have relatively high uncertainty.

These guidelines provide GHG emission and carbon sequestration factors
for each source and sink category in agriculture. In some cases the
factors are relatively generic; in others they are specific to States,
regions, and management practices.

##### 1.H.3.4 Hybrid Estimation Approaches 

In selecting an estimation method for a particular GHG source or sink,
entities will often need to weigh the costs, feasibility, and accuracy
of the different approaches.

A promising approach to balance these considerations is to combine
direct measurement or process models into an inference-based approach.
The accuracy of the inference approach can be greatly improved by
developing emission and sequestration factors that specifically
characterize the reporter's operating conditions.

Direct measurement may be used to develop specialized
emission/sequestration factors that match an entity's conditions. This
involves sampling source categories within an entity rather than
continuous direct measurement of all sources, which reduces resource
requirements while improving the specificity of emission factors. The
samples are used to derive emissions factors for use with simple input
data. Process models may also be used to derive specialized emissions
coefficients for entities, provided they are determined by the reporter
to produce robust estimates of emissions.

##### 1.H.3.5 Rating Scale for Estimation Methods

Multiple estimation methods may be available for a single emissions
source or sink category. In general, these methods will vary in
accuracy, reliability, verifiability and practical application. The
revised Voluntary Reporting of Greenhouse Gases Program includes a
system for ranking alternative estimation methods that encourages
entities to use the most accurate method suitable for their
circumstances. The ranking system is discussed in detail in Chapter 1,
Part A, Section 4 of the Technical Guidelines.

The ranking system provides four possible ratings (A-D) that are applied
to a given estimation method for a specific source or sink. For any
given source or sink, an A, B, C, or D rated method may not be
available.

In these inventory guidelines, the best available methods balance
accuracy and practicality in preparing entity-level annual greenhouse
gas inventories of agricultural sources and sinks. The methods often
rely on a combination of site-specific data and default data based on
national averages. Estimation accuracy is dependent, in part, on the
specificity of entity data inputs and how well entity conditions match
national averages. Using measured entity data, rather than estimates or
samples, will improve estimates and is encouraged.

Ratings for each method are clearly indicated in the guidelines below.
Methods are presented in order from lowest to highest rated. This is
different from other Parts in this Chapter, where the highest rated
method is presented first. In many of the methods detailed below, the
higher rated methods build on default data used by the lower rated
method, lending to a structure that begins with the basic estimate
first.

#### 1.H.4 Category-Specific Estimation Guidance 

##### 1.H.4.1 Livestock Sources

Entities reporting emissions from animal operations will need to
estimate CH~4~ emissions from enteric fermentation and CH~4~ and N~2~O
emissions from livestock waste. The first step in both of those
calculations is to compile information on the entity's animal
populations. Because region-specific emission factors are provided in
several of the methods, entities will need to assess their region(s)
according to definitions provided in this section.

**1.H.4.1.1 Characterizing Animal Populations and Climate Regions**

Each method for estimating emissions from livestock requires an entity
to first characterize livestock populations by determining the number of
animals the entity owns within specific livestock categories. The level
of detail of the characterization varies depending on the estimation
method. Only a simple characterization is needed for sheep, goats, and
horses for all methods. Entities should determine how many they have of
each of these animal categories.

Methods yielding more accurate estimates typically require detailed
characterizations of one or more of the following: beef cattle, dairy
cattle, swine, and poultry. Descriptions of livestock categories for
each of those groups are provided in Table 1.H.1.

Environmental conditions in different climate regions may affect GHG
emissions from livestock sources. Therefore, in addition to
characterizing livestock populations, entities will need to determine
their climate region(s) to use the default emission factors provided.
Most agricultural entities will be within a single climate region. For
entities with operations across the United States, livestock emissions
estimates need to be made separately for each climate region. Climate
regions are defined differently throughout the livestock section
depending on the estimation method. Use the definitions in Tables 1.H.1,
1.H.2, and 1.H.3 when selecting emission factors to use in the
inference-based approaches.

###### Table 1.H.1. Definitions of Livestock Categories 

  -----------------------------------------------------------------------
  **Livestock Category**     **Description**
  -------------------------- --------------------------------------------
  Beef Cattle/Cows           Beef cows that have calved

  Replacement Heifers (0-12  Beef cow replacements age 0-12 months
  mo.)                       

  Replacement Heifers (0-24  Beef cow replacements age 12-24 months
  mo.)                       

  Bulls                      Bulls (\>= 500 lbs.)

  Steer stockers             Feedlot steer, \>= 500 lbs.

  Heifer stockers            All heifers other than feedlot heifers (\>=
                             500 lbs.)

  Steer feedlot              Steer on diets fed to animals on feedlots

  Heifer feedlot             Heifers on diets fed to animals on feedlots

  Steer step-up              Steers on diets fed to animals entering
                             feedlots

  Heifer step-up             Heifers on diets fed to animals entering
                             feedlots

                             

  Dairy Cattle/Cows          Milk cows that have calved

  Replacement Heifers (0-12  Dairy cow replacements age 0-12 months
  mo.)                       

  Replacement Heifers (12-24 Dairy cow replacements age 12-24 months
  mo.)                       

                             

  Swine                      

  Market swine \<60 lbs.     Market swine in the designated weight range

  Market swine 60-119 lbs.   Market swine in the designated weight range

  Market swine 120-179 lbs.  Market swine in the designated weight range

  Market swine \>180 lbs.    Market swine in the designated weight range

  Breeding swine             Swine that are breeding (non-market)

                             

  Poultry                    

  Hens \>/= 1 yr             Female chickens that are laying eggs

  Pullets                    Young female chicken (\<1 yr), category
                             includes laying and non-laying pullets

  Other chickens             Not otherwise categorized (e.g., roosters,
                             mature chickens)

  Broilers                   Young chickens raised for meat production

  Turkeys                    Turkeys raised for meat production
  -----------------------------------------------------------------------

###### Table 1.H.2. Climate Regions Defined by States 

  -----------------------------------------------------------------------
  **Region**       **States in Region**
  ---------------- ------------------------------------------------------
  California       California

  West             Alaska, Washington, Oregon, Idaho, Nevada, Utah,
                   Arizona, Hawaii, New Mexico

  Northern Great   Montana, Wyoming, North Dakota, South Dakota,
  Plains           Nebraska, Kansas, Colorado

  South Central    Arkansas, Louisiana, Okalahoma, Texas

  Northeast        Pennsylvania, New York, Maryland, Delaware, New
                   Jersey, Connecticut, Rhode Island, Massachusetts,
                   Vermont, New Hampshire, Maine, West Virginia, District
                   of Columbia

  Midwest          Missouri, Illinois, Indiana, Ohio, Minnesota,
                   Wisconsin, Michigan, Iowa

  Southeast        Virginia, North Carolina, Kentucky, Tennessee,
                   Mississippi, Alabama, Georgia, South Carolina, Florida
  -----------------------------------------------------------------------

Default values are provided for broad climate regions defined by average
annual mean temperature (Table 1.H.3). Data for determining an entity's
climate region can be found in a number of places: Temperature data can
be readily downloaded from the web site of the NRCS National Water and
Climate Center at
[http://www.wcc.nrcs.usda.gov](http://www.wcc.nrcs.usda.gov/). A
map-based climate information retrieval system is provided at the NRCS
National Water and Climate Center and can be accessed by following links
for "Climate" and "Climate Reports." Entities can use county-level data
on average temperatures to help establish their climate regions. County
temperature data are available from a number of sources including the
NOAA-Regional Climate Centers (see the NOAA web site:
<http://lwf.ncdc.noaa.gov/oa/climate/regionalclimatecenters.html>).

###### Table 1.H.3. Climate Regions Defined by Temperature 

  ----------------------- -----------------------------------------------
  **Region**              **Average mean annual temperature**

  Cool                    \<15 °C

  Temperate               15-25 °C

  Warm                    \> 25 °C
  ----------------------- -----------------------------------------------

**1.H.4.1.2 Enteric Fermentation**

Methane (CH~4~) is produced as a byproduct of normal animal digestion
through "enteric fermentation." Enteric fermentation results from the
breakdown of food by microbial populations that excrete CH~4~, which is
then emitted from the animal to the atmosphere through exhaling or
eructation. Ruminant livestock (including cattle, sheep, and goats) have
greater rates of enteric fermentation because of their unique digestive
system, which contains a large rumen where enteric fermentation takes
place. Non-ruminant livestock (such as swine, horses, and mules) produce
less CH~4~ because enteric fermentation takes place only in the large
intestine. The energy content and quantity of animal feed also affect
CH~4~ emissions from enteric fermentation---lower quality and higher
animal intake of feed generally lead to greater CH~4~ emissions.

**1.H.4.1.2.1 Inference Using Default Emission Factors**

**Rating: B**

A general estimate of the methane production by ruminants can be
developed using emission factors in Table 1.H.4. The approach uses the
equation below and follows these steps: First, characterize cattle
populations and climate region(s) within entity boundaries using the
definitions provided above under "Characterizing Animal Populations and
Climate Regions." Next, multiply the population numbers for each cattle
category by the appropriate emission factor in Table 1.H.4. For other,
non-cattle livestock, multiply population numbers by default emission
factors (non-region-specific) in Table 1.H.5. Finally, sum population
emission estimates for an entity total.

**CH~4~ = ∑ P~i~ \* EF~i~**

> **Where:**
>
> **P~i~ = population size of livestock category i**
>
> **EF~i~ = emission factor for livestock category i (specific to entity
> region for cattle categories)**

###### Table 1.H.4. Methane Emission Factors for U.S. Cattle by Region (kg CH~4~/head/year) 

+------------+-------+----+----------+-------+-------+------+-------+
| **Animal** | **Ca  | ** | **       | **    | **N   | **M  | **S   |
|            | lifor | We | Northern | South | orthe | idwe | outhe |
|            | nia** | st | Great    | -cent | ast** | st** | ast** |
|            |       | ** | Plains** | ral** |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+
| Beef Cows  | 73.8  | 85 | 71.8     | 74.6  | 74.1  | 74.1 | 74.7  |
|            |       | .3 |          |       |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+
| Beef       | 40.2  | 46 | 39.0     | 40.6  | 40.3  | 40.3 | 40.7  |
| R          |       | .8 |          |       |       |      |       |
| eplacement |       |    |          |       |       |      |       |
| Heifer     |       |    |          |       |       |      |       |
|            |       |    |          |       |       |      |       |
| (0-12 mo.) |       |    |          |       |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+
| Beef       | 62.9  | 73 | 61.0     | 63.6  | 63.1  | 63.2 | 63.7  |
| R          |       | .8 |          |       |       |      |       |
| eplacement |       |    |          |       |       |      |       |
| Heifer     |       |    |          |       |       |      |       |
|            |       |    |          |       |       |      |       |
| (12-24     |       |    |          |       |       |      |       |
| mo.)       |       |    |          |       |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+
| Steer      | 54.1  | 63 | 52.5     | 54.8  | 54.4  | 54.4 | 54.9  |
| Stockers   |       | .7 |          |       |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+
| Heifer     | 48.5  | 56 | 47.0     | 49.0  | 48.7  | 48.7 | 49.1  |
| Stockers   |       | .8 |          |       |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+
| Steer      | 33.2  | 33 | 33.5     | 33.6  | 33.5  | 33.7 | 33.9  |
| Feedlot    |       | .5 |          |       |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+
| Heifer     | 31.3  | 31 | 31.6     | 31.7  | 31.6  | 31.8 | 32.0  |
| Feedlot    |       | .6 |          |       |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+
| Bulls      | 100.0 | 1  | 100.0    | 100.0 | 100.0 | 1    | 100.0 |
|            |       | 00 |          |       |       | 00.0 |       |
|            |       | .0 |          |       |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+
| Dairy Cows | 107.2 | 1  | 117.4    | 108.4 | 117.2 | 1    | 108.4 |
|            |       | 37 |          |       |       | 15.4 |       |
|            |       | .0 |          |       |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+
| Dairy      | 40.3  | 40 | 38.1     | 45.5  | 40.7  | 38.1 | 46.9  |
| R          |       | .3 |          |       |       |      |       |
| eplacement |       |    |          |       |       |      |       |
| Heifer     |       |    |          |       |       |      |       |
|            |       |    |          |       |       |      |       |
| (0-12 mo.) |       |    |          |       |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+
| Dairy      | 63.3  | 63 | 59.9     | 71.6  | 63.9  | 59.9 | 73.7  |
| R          |       | .3 |          |       |       |      |       |
| eplacement |       |    |          |       |       |      |       |
| Heifer     |       |    |          |       |       |      |       |
|            |       |    |          |       |       |      |       |
| (12-24     |       |    |          |       |       |      |       |
| mo.)       |       |    |          |       |       |      |       |
+------------+-------+----+----------+-------+-------+------+-------+

Source: U.S. Environmental Protection Agency. 2005. Emission Inventory
Improvement Program. Volume VIII. Chapter 7. Methods for Estimating
Methane Emissions from Domesticated Animals, Table 7.4-4.

###### Table 1.H.5. Methane Emission Factors for Non-cattle Livestock Categories (kg CH~4~/head/year) 

  ----------------------------------- -----------------------------------
  **Livestock Category**              **Emission factor**

  Sheep                               8

  Goats                               5

  Swine                               1.5

  Horses                              18
  ----------------------------------- -----------------------------------

Source: Intergovernmental Panel on Climate Change. 1997. *Revised 1996
IPCC Guidelines for National Greenhouse Gas Inventories*. Reference
Manual (Volume 3). Chapter 4: Agriculture. Paris, France, (see Table 4.3
on page 4.10).

**1.H.4.1.2.2 Inference Using Improved Emission Factors**

**Rating: A**

Given the relative importance of enteric fermentation emissions from
beef and dairy cattle, entities can improve their greenhouse gas
inventories from livestock by applying specialized emission factors for
cattle into the equation provided immediately above (i.e., in
1.H.4.1.2.1). Guidance is provided below on how to develop specialized
emission factors for several categories of cattle based on livestock
diet characteristics. For each type of cattle maintained by an entity or
sub-entity, the reporter should develop an emission factor using the
equation below. For all other livestock categories, the default emission
factors provided in Table 1.H.5 should be used.

**EF~i~ = (GE \* Y~m~ \* 365 days/yr) / (55.65 MJ/kg CH~4~)**

> **Where:**

**EF~i~ = emission factor for cattle category i (kilograms of methane
per head per year)\
**

**GE = gross energy intake (MJ/head/day)\
**

**Y~m~ = conversion rate of gross energy intake to methane (specific to
entity region and is the fraction of GE in feed converted to methane)**

GE can be estimated from the total amount of feed given to a livestock
group daily, divided by the number of animals in that group, and
multiplied by the metabolizable energy (ME) content of the feed. ME
values for common feed types are published by the National Research
Council and are reproduced in Table 1.H.A.25 at the end of Part H.

The Environmental Protection Agency (EPA) estimates for methane
conversion rates (Y~m~) for different groups of cattle are provided in
Table 1.H.6. Regions and cattle categories are defined above under
"Characterizing Animal Populations and Climate Regions.

###### Table 1.H.6. Methane Conversion Rates (Y~m~) for Cattle, by Region

+----------+--------+-----+-------+------+--------+-------+---------+
| **Liv    | **     | **  | **    | *    | *      | *     | **Sout  |
| estock** | Califo | Wes | North | *Sou | *North | *Midw | heast** |
|          | rnia** | t** | ern** | th** | east** | est** |         |
| **Ca     |        |     |       |      |        |       |         |
| tegory** |        |     | **    | **c  |        |       |         |
|          |        |     | Great | entr |        |       |         |
|          |        |     | Pla   | al** |        |       |         |
|          |        |     | ins** |      |        |       |         |
+==========+========+=====+=======+======+========+=======+=========+
| Beef     | 0.065  | 0.  | 0.065 | 0    | 0.065  | 0.065 | 0.065   |
| rep      |        | 065 |       | .065 |        |       |         |
| lacement |        |     |       |      |        |       |         |
| heifer   |        |     |       |      |        |       |         |
+----------+--------+-----+-------+------+--------+-------+---------+
| Steer    | 0.065  | 0.  | 0.065 | 0    | 0.065  | 0.065 | 0.065   |
| Stocker  |        | 065 |       | .065 |        |       |         |
+----------+--------+-----+-------+------+--------+-------+---------+
| Heifer   | 0.065  | 0.  | 0.065 | 0    | 0.065  | 0.065 | 0.065   |
| Stocker  |        | 065 |       | .065 |        |       |         |
+----------+--------+-----+-------+------+--------+-------+---------+
| Beef     | 0.065  | 0.  | 0.065 | 0    | 0.065  | 0.065 | 0.065   |
| Cows     |        | 065 |       | .065 |        |       |         |
+----------+--------+-----+-------+------+--------+-------+---------+
| Steer    | 0.030  | 0.  | 0.030 | 0    | 0.030  | 0.030 | 0.030   |
| Feedlot  |        | 030 |       | .030 |        |       |         |
+----------+--------+-----+-------+------+--------+-------+---------+
| Heifer   | 0.030  | 0.  | 0.030 | 0    | 0.030  | 0.030 | 0.030   |
| Feedlot  |        | 030 |       | .030 |        |       |         |
+----------+--------+-----+-------+------+--------+-------+---------+
| Steer    | 0.048  | 0.  | 0.048 | 0    | 0.048  | 0.048 | 0.048   |
|          |        | 048 |       | .048 |        |       |         |
| Step-up  |        |     |       |      |        |       |         |
+----------+--------+-----+-------+------+--------+-------+---------+
| Heifer   | 0.048  | 0.  | 0.048 | 0    | 0.048  | 0.048 | 0.048   |
| Step-up  |        | 048 |       | .048 |        |       |         |
+----------+--------+-----+-------+------+--------+-------+---------+
| Diary    | 0.059  | 0.  | 0.056 | 0    | 0.063  | 0.056 | 0.069   |
| rep      |        | 059 |       | .064 |        |       |         |
| lacement |        |     |       |      |        |       |         |
| heifer   |        |     |       |      |        |       |         |
+----------+--------+-----+-------+------+--------+-------+---------+
| Dairy    | 0.048  | 0.  | 0.058 | 0    | 0.058  | 0.058 | 0.056   |
| cows     |        | 058 |       | .057 |        |       |         |
+----------+--------+-----+-------+------+--------+-------+---------+

Source: U.S. Environmental Protection Agency. 2005. *Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2003*. Annex 3. Table 3-83,
page 177.

**1.H.4.1.2.3 Alternative Approach for Enteric Fermentation**

Entities can use measurement techniques to estimate methane emissions
from grazing livestock at the herd level. This approach requires the
entity to take samples from experimental animals on similar diets and
with similar energy requirements.

The sulfur hexafluoride (SF~6~) tracer technique (Johnson 2004) can be
used to estimate methane emissions from selected animals and expanded to
herd levels in specific locations. A small permeation tube containing
SF~6~ is introduced into the rumen and releases the inert gas at a
constant rate. The SF~6~ is captured via a vacuum tube and halter fitted
for the animal. Methane and SF~6~ concentrations in the vacuum tube are
then analyzed using gas chromatography to predict the rate of methane
production.

This method to predict changes in methane production is suitable for
reporting greenhouse gas emission changes if a representative sample of
animals are selected. At a minimum, a herd should be stratified by
reproductive status (breeding females, breeding males, nonbreeding
females, calves) and animal breed. The reproductive groups should be
further stratified by weight and/or age if the weight of animals within
a group varies by more than 25 percent of the average and/or the age of
animals within a group varies by more than three years.

Because diet quality is an important determinant of methane production,
sample animals must be exposed to diets that are similar to the entire
herd. Sample animals should also reflect the age, breed and reproductive
structure of the herd(s).

The SF~6~ method is experimental and has been proven only within a
portion of the range of conditions encountered by commercial livestock
grazing. Using this technique to estimate emission reductions requires
substantial knowledge of ruminant physiology, grazing animal behavior,
gas chromatography and statistical analysis. Because the default enteric
fermentation emission factors and Y~m~ values provided above have been
developed based on regional averages, there is uncertainty associated
with them in a site-specific situation. Reducing the uncertainty of
estimates based on default data can be accomplished by using
locally-available research or by obtaining direct measurement of
emissions from individual animals (via negative pressure sampling
collars and sulfur hexafluoride tracer method) and expanding those
estimates to a herd level using statistical techniques (Johnson and
Johnson 1995). The cost effectiveness of this approach can be enhanced
by applying it to several similar herds in an area using a project
approach.

Entities developing methods for estimating emissions from enteric
fermentation based on the SF~6~ technique must follow the guidelines for
new methods provided in Chapter 1, Part A, Section A.4.

**1.H.4.1.3 Livestock Waste**

CH~4~ and N~2~O emissions from waste are caused by the biological
breakdown of organic matter in the waste. Livestock waste can be managed
with storage and treatment systems, or spread daily on fields in lieu of
long-term storage. In some cases, livestock waste is "unmanaged" and is
deposited directly on pastures, ranges, or paddocks while animals graze.
Table 1.H.7 provides descriptions of managed and unmanaged systems for
livestock waste, indicating in general terms the impacts of different
systems on GHG emissions. Livestock waste that is stored and treated is
sometimes applied subsequently as a nutrient amendment to agricultural
soils. Emissions from manure applications are covered below in the
subsection titled "N~2~O from Agricultural Soils."

###### Table 1.H.7. Livestock waste and GHG emissions

+-------------------+----------------------------+----------+---------+
| **Livestock       | **Description**            | **       | **R     |
| Category**        |                            | Relative | elative |
|                   |                            | CH~4~**  | N~2~O** |
|                   |                            |          |         |
|                   |                            | **Emi    | **Emis  |
|                   |                            | ssions** | sions** |
+===================+============================+==========+=========+
| Past              | Waste from pasture- and    | Low      | High    |
| ure/range/paddock | range-grazing animals is   |          |         |
|                   | deposited directly onto    |          |         |
|                   | the soil.                  |          |         |
+-------------------+----------------------------+----------+---------+
| Daily spread      | Waste is collected and     | Low      | see     |
|                   | spread on fields. There is |          | note    |
|                   | little or no storage of    |          | (1) at  |
|                   | the waste before it is     |          | end of  |
|                   | applied to soils.          |          | table   |
+-------------------+----------------------------+----------+---------+
| Solid storage     | Waste (with or without     | Low      | High    |
|                   | litter) is collected by    |          |         |
|                   | some means and placed      |          |         |
|                   | under long-term bulk       |          |         |
|                   | storage.                   |          |         |
+-------------------+----------------------------+----------+---------+
| Dry lot           | Waste is deposited         | Low      | High    |
|                   | directly onto unpaved      |          |         |
|                   | feedlots where the manure  |          |         |
|                   | is allowed to dry and is   |          |         |
|                   | periodically removed       |          |         |
|                   | (after removal it is       |          |         |
|                   | sometimes spread onto      |          |         |
|                   | fields).                   |          |         |
+-------------------+----------------------------+----------+---------+
| Liquid/slurry     | Waste is collected and     | Moderate | Low     |
|                   | transported in a liquid    | to high  |         |
|                   | state to tanks for         |          |         |
|                   | storage. The liquid/slurry |          |         |
|                   | mixture may be stored for  |          |         |
|                   | a long time and water may  |          |         |
|                   | be added to facilitate     |          |         |
|                   | handling.                  |          |         |
+-------------------+----------------------------+----------+---------+
| Anaerobic lagoon  | Waste is collected using a | Variable | Low     |
|                   | flush system and           |          |         |
|                   | transported to lagoons for |          |         |
|                   | storage. Waste resides in  |          |         |
|                   | lagoons for 30-200 days.   |          |         |
+-------------------+----------------------------+----------+---------+
| Pit storage       | Waste is stored in pits    | Moderate | Low     |
|                   | below livestock            | to high  |         |
|                   | confinements.              |          |         |
+-------------------+----------------------------+----------+---------+
| Poultry house     | Waste is excreted on       | Low      | High    |
| with bedding      | poultry house floor        |          |         |
|                   | covered with bedding;      |          |         |
|                   | poultry can walk on the    |          |         |
|                   | floor.                     |          |         |
+-------------------+----------------------------+----------+---------+
| Poultry house     | Waste is excreted on       | Low      | Low     |
| without bedding   | poultry house floor, which |          |         |
|                   | is not covered with        |          |         |
|                   | bedding; poultry cannot    |          |         |
|                   | walk on the floor.         |          |         |
+-------------------+----------------------------+----------+---------+

Source: Intergovernmental Panel on Climate Change. 2000. *Good Practice
Guidance and Uncertainty Management in National Greenhouse Gas
Inventories*. Chapter 4. IPCC National Greenhouse Gas Inventories
Programme Technical Support Unit. Japan Tables 4.10, table 4.11, and
4.12.

\(1\) IPCC table 4.12 considers N~2~O emissions from excretion. N~2~O
emissions from "daily spread" are considered under manure management. In
the 1605b Technical Guidelines, methods for estimating N~2~O emissions
from daily spread are described in Section 1.H.4.2.3 N~2~O from
Agricultural Soils.

**1.H.4.1.3.1 Inference Using Emission Factors Specific to Livestock
Category and Waste Management System - Methane (CH~4~)**

**Rating: B**

Reporters should follow the same general process as for enteric
fermentation: characterize the livestock populations owned by the
entity; multiply the population categories by the appropriate emission
factor; and sum the estimates for all population categories.

**CH~4~ = ∑ P~i~ \* EF~i~**

> **Where:**

**P~i~ = population size of livestock category i**

**EF~i~ = CH~4~ emission factor for livestock category i (specific to
entity**

**region for cattle categories)**

Guidance is provided below on how to develop specialized emission
factors based on livestock characteristics and waste management systems
for cattle, swine, and poultry. For horses, sheep, and goats, multiply
population numbers by default emissions factors in Table 1.H.8, choosing
the factor most appropriate for your climate region.

###### Table 1.H.8. Default Methane Emissions Factors for Waste from Sheep, Goats, or Horses (kilograms of methane per head per year) 

  ------------------ -------------- --------------- -----------------------
  **Livestock        **Climate                      
  Category**         Region**                       

                     **Cool**       **Temperate**   **Warm**

  Sheep              0.19           0.28            0.37

  Goats              0.12           0.18            0.23

  Horses             1.4            2.1             2.8
  ------------------ -------------- --------------- -----------------------

Source: Intergovernmental Panel on Climate Change. 1997. Revised 1996
IPCC Guidelines for National Greenhouse Gas Inventories. Reference
Manual (Volume 3). Chapter 4: Agriculture. Paris, France. (see Table
4.5). For cattle, swine, and poultry, further subdivide population data
by system used to manage waste. For each combination of livestock type
and waste management system maintained by an entity or sub-entity,
develop an emission factor using the equation below and coefficients
provided in Tables 1.H.9, 1.H.10, 1.H.11, and 1.H.12.

**EF~i,j~ = VS~i~ (Mass) \* 365 days/yr \* Bo~i~ \* 0.67 kg/m^3^ \*
MCF~i,j~**

**Where:**

**EF~i,j~ = emissions factor for CH~4~ from waste for livestock category
i in**

**management system j (kilograms of methane per head per year)**

**VS~i~ = daily volatile solid excreted per 1,000 kg mass by livestock
category i (kilograms of volatile solids per 1,000 kg of animal mass per
day)**

**Mass = average animal mass in 1,000 kg for livestock category i (1,000
kilograms of animal mass)**

**Bo~i~ = maximum CH~4~ producing capacity for manure produced by an
animal in category i (cubic meters of methane per kilogram of volatile
solids)**

**MCF~i,j~ = methane conversion factor for livestock category i in
management**

> **system j**

EPA developed estimates of VS and Bo for cattle, swine, and poultry
categories. National-level estimates for Bo by livestock category are
provided in Table 1.H.9, as are national-level VS values for some
livestock categories. As indicated in the table, State-level VS values
for the other livestock categories can be found in Table 1.H.10. If
entities have data on volatile solids excretion or can derive an
estimate based on waste produced per day, those data should be used in
place of State-level defaults. Entities will also need to estimate or
measure directly the average animal mass for each livestock category
based on entity records.

###### Table 1.H.9. Volatile Solids (VS) and Maximum Methane Producing Capacity (Bo) Values for Cattle, Swine, and Poultry 

  -----------------------------------------------------------------------
  **Livestock**            **Max Methane       **Volatile Solids VS**
                           Generation          
                           Potential, Bo**     
  ------------------------ ------------------- --------------------------
                           **m ^3^ CH~4~/kg VS **kg/day per 1,000 kg
                           added**             mass**

  Dairy cow                0.24                see Table 1.H.10

  Dairy heifer             0.17                see Table 1.H.10

  Feedlot steers           0.33                see Table 1.H.10

  Feedlot heifers          0.33                see Table 1.H.10

  Not on feed, bulls       0.17                6.04

  Not on feed, calves      0.17                6.41

  Not on feed, heifers     0.17                see Table 1.H.10

  Not on feed, steers      0.17                see Table 1.H.10

  NOF cows                 0.17                see Table 1.H.10

  Market swine \<60 lbs.   0.48                8.8

  Market swine 60-119 lbs. 0.48                5.4

  Market swine 120-179     0.48                5.4
  lbs.                                         

  Market swine \>180 lbs.  0.48                5.4

  Breeding swine           0.48                2.6

  Hens \>/= 1 yr           0.39                10.8

  Pullets                  0.39                9.7

  Other chickens           0.39                10.8

  Broilers                 0.36                15

  Turkeys                  0.36                9.7
  -----------------------------------------------------------------------

Source: Environmental Protection Agency. 2005. Emission Inventory
Improvement Program. Volume VIII. Chapter 8. Methods for Estimating
Greenhouse Gas Emissions from Livestock Manure Management, Table 8.4-2.

###### Table 1.H.10. Volatile Solids (VS~i~) by State for Cattle Groups (kg/day per 1,000 kg mass) 

+-------------+-------+-------+-------+-------+-------+-------+------+
| **State**   | **    | **    | **    | **Hei | **St  | *     | *    |
|             | Dairy | Dairy | Cows, | fers, | eers, | *Feed | *Fee |
|             | Cow** | Hei   | not   | not   | not   | lot** | dlot |
|             |       | fer** | on    | on    | on    |       | Stee |
|             |       |       | f     | f     | f     | *     | rs** |
|             |       |       | eed** | eed** | eed** | *Heif |      |
|             |       |       |       |       |       | ers** |      |
+=============+=======+=======+=======+=======+=======+=======+======+
| Alabama     | 8.50  | 6.82  | 6.74  | 7.22  | 7.72  | 4.06  | 3.89 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Alaska      | 10.87 | 6.82  | 8.71  | 9.50  | 10.21 | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Arizona     | 10.87 | 6.82  | 8.71  | 9.53  | 10.21 | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Arkansas    | 8.58  | 7.57  | 6.72  | 7.20  | 7.70  | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| California  | 9.38  | 6.82  | 6.57  | 7.06  | 7.51  | 3.96  | 3.80 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Colorado    | 8.68  | 6.82  | 6.19  | 6.67  | 7.04  | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Connecticut | 8.44  | 6.14  | 6.62  | 7.13  | 7.58  | 4.01  | 3.84 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Delaware    | 8.44  | 6.14  | 6.62  | 7.14  | 7.58  | 4.01  | 3.84 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Florida     | 8.50  | 6.82  | 6.74  | 7.20  | 7.72  | 4.06  | 3.89 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Georgia     | 8.50  | 6.82  | 6.74  | 7.22  | 7.72  | 4.06  | 3.89 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Hawaii      | 10.87 | 6.82  | 8.71  | 9.52  | 10.21 | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Idaho       | 10.87 | 6.82  | 8.71  | 9.59  | 10.21 | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Illinois    | 8.54  | 6.82  | 6.63  | 7.15  | 7.58  | 3.96  | 3.80 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Indiana     | 8.54  | 6.82  | 6.63  | 7.13  | 7.58  | 3.96  | 3.80 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Iowa        | 8.54  | 6.82  | 6.63  | 7.17  | 7.58  | 3.96  | 3.80 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Kansas      | 8.68  | 6.82  | 6.19  | 6.67  | 7.04  | 4.03  | 3.86 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Kentucky    | 8.50  | 6.82  | 6.74  | 7.24  | 7.72  | 4.06  | 3.89 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Louisiana   | 8.58  | 7.57  | 6.72  | 7.08  | 7.70  | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Maine       | 8.44  | 6.14  | 6.62  | 7.18  | 7.58  | 4.01  | 3.84 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Maryland    | 8.44  | 6.14  | 6.62  | 7.11  | 7.58  | 4.01  | 3.84 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Ma          | 8.44  | 6.14  | 6.62  | 7.12  | 7.58  | 4.01  | 3.84 |
| ssachusetts |       |       |       |       |       |       |      |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Michigan    | 8.54  | 6.82  | 6.63  | 7.13  | 7.58  | 3.96  | 3.80 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Minnesota   | 8.54  | 6.82  | 6.63  | 7.14  | 7.58  | 3.96  | 3.80 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Mississippi | 8.50  | 6.82  | 6.74  | 7.21  | 7.72  | 4.06  | 3.89 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Missouri    | 8.54  | 6.82  | 6.63  | 7.12  | 7.58  | 3.96  | 3.80 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Montana     | 8.68  | 6.82  | 6.19  | 6.60  | 7.04  | 4.03  | 3.86 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Nebraska    | 8.68  | 6.82  | 6.19  | 6.67  | 7.04  | 4.03  | 3.86 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Nevada      | 10.87 | 6.82  | 8.71  | 9.54  | 10.21 | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| New         | 8.44  | 6.14  | 6.62  | 7.08  | 7.58  | 4.01  | 3.84 |
| Hampshire   |       |       |       |       |       |       |      |
+-------------+-------+-------+-------+-------+-------+-------+------+
| New Jersey  | 8.44  | 6.14  | 6.62  | 7.11  | 7.58  | 4.01  | 3.84 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| New Mexico  | 10.87 | 6.82  | 8.71  | 9.56  | 10.21 | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| New York    | 8.44  | 6.14  | 6.62  | 7.14  | 7.58  | 4.01  | 3.84 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| North       | 8.50  | 6.82  | 6.74  | 7.21  | 7.72  | 4.06  | 3.89 |
| Carolina    |       |       |       |       |       |       |      |
+-------------+-------+-------+-------+-------+-------+-------+------+
| North       | 8.68  | 6.82  | 6.19  | 6.64  | 7.04  | 4.03  | 3.86 |
| Dakota      |       |       |       |       |       |       |      |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Ohio        | 8.54  | 6.82  | 6.63  | 7.12  | 7.58  | 3.96  | 3.80 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Oklahoma    | 8.58  | 7.57  | 6.72  | 7.24  | 7.70  | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Oregon      | 10.87 | 6.82  | 8.71  | 9.55  | 10.21 | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| P           | 8.44  | 6.14  | 6.62  | 7.12  | 7.58  | 4.01  | 3.84 |
| ennsylvania |       |       |       |       |       |       |      |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Rhode       | 8.44  | 6.14  | 6.62  | 7.08  | 7.58  | 4.01  | 3.84 |
| Island      |       |       |       |       |       |       |      |
+-------------+-------+-------+-------+-------+-------+-------+------+
| South       | 8.50  | 6.82  | 6.74  | 7.22  | 7.72  | 4.06  | 3.89 |
| Carolina    |       |       |       |       |       |       |      |
+-------------+-------+-------+-------+-------+-------+-------+------+
| South       | 8.68  | 6.82  | 6.19  | 6.64  | 7.04  | 4.03  | 3.86 |
| Dakota      |       |       |       |       |       |       |      |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Tennessee   | 8.50  | 6.82  | 6.74  | 7.22  | 7.72  | 4.06  | 3.89 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Texas       | 8.58  | 7.57  | 6.72  | 7.25  | 7.70  | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Utah        | 10.87 | 6.82  | 8.71  | 9.55  | 10.21 | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Vermont     | 8.44  | 6.14  | 6.62  | 7.12  | 7.58  | 4.01  | 3.84 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Virginia    | 8.50  | 6.82  | 6.74  | 7.23  | 7.72  | 4.06  | 3.89 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Washington  | 10.87 | 6.82  | 8.71  | 9.59  | 10.21 | 4.03  | 3.87 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| West        | 8.44  | 6.14  | 6.62  | 7.10  | 7.58  | 4.01  | 3.84 |
| Virginia    |       |       |       |       |       |       |      |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Wisconsin   | 8.54  | 6.82  | 6.63  | 7.12  | 7.58  | 3.96  | 3.80 |
+-------------+-------+-------+-------+-------+-------+-------+------+
| Wyoming     | 8.68  | 6.82  | 6.19  | 6.63  | 7.04  | 4.03  | 3.86 |
+-------------+-------+-------+-------+-------+-------+-------+------+

Source: Environmental Protection Agency. 2005. *Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2003*. Annex 3. Table 3-90,
page 189.

State-level default methane conversion factors (MCF) for pasture, range
and paddock, dry lot systems, and liquid systems (i.e., anaerobic
lagoons) are provided in Table 1.H.11. Default emission factors
developed by the Intergovernmental Panel on Climate Change (IPCC) and
categorized by broad climate region for all other common management
systems are in Table 1.H.12.

###### Table 1.H.11. State-level Methane Conversion Factors (MCF) for Pasture, Range and Paddocks, Drylots, and Liquid Systems

  ------------------------------------------------------------------------------
  **State**       **Range &      **Drylot ^1^** **Liquid/Slurry & **Anaerobic
                  Paddocks ^1^**                Deep Pit**        Lagoon**
  --------------- -------------- -------------- ----------------- --------------
  Alabama         0.014          0.019          0.385             0.758

  Alaska          NA             NA             0.138             0.483

  Arizona         0.014          0.019          0.448             0.793

  Arkansas        0.013          0.018          0.361             0.65

  California      0.012          0.014          0.377             0.762

  Colorado        0.009          0.01           0.222             0.667

  Connecticut     0.009          0.01           0.239             0.694

  Delaware        0.012          0.014          0.297             0.739

  Florida         0.015          0.024          0.552             0.778

  Georgia         0.014          0.018          0.383             0.756

  Hawaii          NA             NA             0.597             0.771

  Idaho           0.008          0.008          0.232             0.683

  Illinois        0.011          0.013          0.269             0.715

  Indiana         0.01           0.012          0.260             0.706

  Iowa            0.009          0.011          0.247             0.697

  Kansas          0.011          0.015          0.319             0.745

  Kentucky        0.012          0.015          0.304             0.732

  Louisiana       0.014          0.021          0.461             0.772

  Maine           0.008          0.008          0.195             0.633

  Maryland        0.011          0.012          0.276             0.721

  Massachusetts   0.009          0.01           0.232             0.687

  Michigan        0.008          0.009          0.220             0.667

  Minnesota       0.008          0.008          0.228             0.679

  Mississippi     0.014          0.019          0.401             0.761

  Missouri        0.011          0.014          0.304             0.738

  Montana         0.007          0.008          0.211             0.659

  Nebraska        0.01           0.011          0.267             0.715

  Nevada          0.012          0.014          0.257             0.705

  New Hampshire   0.008          0.008          0.210             0.655

  New Jersey      0.01           0.011          0.264             0.719

  New Mexico      0.012          0.013          0.326             0.744

  New York        0.009          0.009          0.217             0.666

  North Carolina  0.013          0.015          0.337             0.744

  North Dakota    0.007          0.007          0.217             0.669

  Ohio            0.01           0.011          0.248             0.695

  Oklahoma        0.014          0.019          0.365             0.761

  Oregon          0.011          0.011          0.228             0.670

  Pennsylvania    0.009          0.01           0.252             0.704

  Rhode Island    0.01           0.011          0.246             0.704

  South Carolina  0.013          0.017          0.378             0.758

  South Dakota    0.008          0.009          0.242             0.696

  Tennessee       0.013          0.016          0.326             0.742

  Texas           0.014          0.021          0.416             0.770

  Utah            0.009          0.01           0.262             0.771

  Vermont         0.008          0.008          0.202             0.645

  Virginia        0.012          0.014          0.279             0.720

  Washington      0.01           0.01           0.233             0.679

  West Virginia   0.012          0.013          0.253             0.698

  Wisconsin       0.008          0.008          0.224             0.677

  Wyoming         0.008          0.008          0.213             0.660
  ------------------------------------------------------------------------------

NA = not available

Sources:

1\. Environmental Protection Agency. 2005. Emission Inventory
Improvement Program. Volume VIII. Chapter 8. Methods for Estimating
Greenhouse Gas Emissions from Livestock Manure Management. See Table
8.4-12.

2\. Environmental Protection Agency. 2005. *Inventory of U.S. Greenhouse
Gas Emissions and Sinks: 1990-2003*. Annex 3. Table 3-97.

###### Table 1.H.12. Methane Conversion Factors (MCF) for Select Management Systems (Ratio of Actual to Maximum Possible Methane Production)

+----------------------------+-------------+-------------+-------------+
| **System**                 | **Cool**    | **          | **Warm**    |
|                            |             | Temperate** |             |
+============================+=============+=============+=============+
| Daily spread               | 0.001       | 0.005       | 0.01        |
+----------------------------+-------------+-------------+-------------+
| Solid storage              | 0.01        | 0.015       | 0.02        |
+----------------------------+-------------+-------------+-------------+
| Pit storage                |             |             |             |
+----------------------------+-------------+-------------+-------------+
| > Short term (\< 1 month)  | 0           | 0           | 0.3         |
+----------------------------+-------------+-------------+-------------+
| > Long term (\>1 month)    | 0.39        | 0.45        | 0.72        |
+----------------------------+-------------+-------------+-------------+
| Poultry house with bedding | 0.015       | 0.015       | 0.015       |
+----------------------------+-------------+-------------+-------------+
| Poultry house without      | 0.015       | 0.015       | 0.015       |
| bedding                    |             |             |             |
+----------------------------+-------------+-------------+-------------+

Source: Intergovernmental Panel on Climate Change. 2000. *Good Practice
Guidance and Uncertainty Management in National Greenhouse Gas
Inventories*. Chapter 4. IPCC National Greenhouse Gas Inventories
Programme Technical Support Unit. Japan Table 4.10, pp. 4.35-4.36.

**1.H.4.1.3.2 Inference Using Emission Factors Specific to Livestock
Category and Waste Management System -- Nitrous Oxide (N~2~O)**

**Rating: B**

Reporters should divide livestock populations into the management system
categories shown in Table 1.H.13, and then multiply each livestock
population by the appropriate N~2~O emissions factor also shown in Table
1.H.13. Emission factors are based on default data published by the
IPCC.

###### Table 1.H.13. N~2~O Emission Factors for Livestock by Waste Management System in the United States (kilograms of nitrous oxide per head per year)

  ------------------- -------------- ----------- ------------- --------------
  **Livestock         **Anaerobic    **Liquid    **Solid**     **Pasture,**
  Category**          Lagoon**       System**    **Storage     **Range**
                                                 and**         **Grazing**
                                                 **Drylot**    **Systems**

  Non-Dairy Cattle    0.11           0.11        2.20          2.20

  Dairy/Feedlot       0.16           0.16        3.14          3.14
  Cattle                                                       

  Poultry             0.0009         0.0009      0.02          0.02

  Sheep               0.03           0.03        0.50          0.50

  Swine               0.03           0.03        0.63          0.63
  ------------------- -------------- ----------- ------------- --------------

Source: Intergovernmental Panel on Climate Change. 1997. *Revised 1996
IPCC Guidelines for National Greenhouse Gas Inventories*. Reference
Manual (Volume 3). Chapter 4: Agriculture. Paris, France, Tables 4-20
and Table 4-22.

Because the factors driving methane production from livestock waste are
somewhat responsive to site-specific conditions (diet quality,
temperature, precipitation, variations in method of handling, etc.) the
estimation methods described here are uncertain when applied to a
specific situation.

**1.H.4.1.3.3 Additional Resources**

Anaerobic digesters are components of waste treatment systems that
promote the production and capture of methane gas, which can then be
used to produce energy. There are numerous designs for anaerobic
digesters that generally consist of an airtight cover over a waste
impoundment.

An introduction to anaerobic digester technologies and guidance on the
selection, implementation, and management of technologies to capture
methane emissions from livestock wastes is in the EPA publication,
*AgStar Biogas Handbook* (available at the web site:
http://www.epa.gov/agstar/resources/handbook.html). EPA's FarmWare
software is described in Appendix C of the *AgStar Biogas Handbook.*

Guidance on designing and implementing animal waste management practices
is provided by USDA NRCS in the "National Conservation Practice
Standards." The complete set of "National Conservation Practice
Standards" can be found at web site:
www.nrcs.usda.gov/Technical/Standards/index.html.

1.H.4.2 Crop Production Sources

**1.H.4.2.1 Residue Burning**

Burning crop residues and native vegetation is not considered to be a
significant source of carbon dioxide released in the United States.
Carbon dioxide released during burning is generally taken up by
vegetation the following growing season and is not considered a source
of anthropogenic carbon dioxide emissions. Field burning of crop
residues emits nitrous oxide and methane to the atmosphere. Methods
below can be used to estimate nitrous oxide and methane emissions from
residue burning. The methods are based on national averages combined
with site-specific information on crop production and burning activity.

**1.H.4.2.1.1 Inference Using Default Emission Factors -- Nitrous Oxide
(N2O)**

**Rating: B**

Nitrous oxide emissions from residue burning can be estimated based on
the amount of crops produced and the fraction burned annually (IPCC
1997). In addition, data are needed on the ratio of residue to crop
product, dry matter content of residue, burning efficiency, nitrogen
content, and combustion efficiency. National defaults for these data
were developed by the EPA and are provided in Table 1.H.14 (EPA 2003).
Finally, an N~2~O emission factor is used to convert the amount of
nitrogen released to nitrous oxide emissions.

###### Table 1.H.14. Default Data for Estimating N~2~O and CH~4~ Emissions from Burning of Crop Residues 

  ------------------------------------------------------------------------------------------------------------
  **Parameter**    **Corn**   **Peanuts**   **Soybeans**   **Barley**   **Wheat**   **Rice**   **Sugarcane**
  ---------------- ---------- ------------- -------------- ------------ ----------- ---------- ---------------
  Ratio            1          1             2.1            1.2          1.3         1.4        0.8
  residue:crop                                                                                 

  DM (Dry Matter   0.91       0.86          0.87           0.93         0.93        0.91       0.62
  Content of                                                                                   
  Residues)                                                                                    

  BE (Burning      0.93       0.93          0.93           0.93         0.93        0.93       0.93
  Efficiency)                                                                                  

  CE (Combustion   0.88       0.88          0.88           0.88         0.88        0.88       0.88
  Efficiency)                                                                                  

  C-Content        0.4478     0.45          0.45           0.4485       0.4428      0.3806     0.4235
  (Carbon Content)                                                                             

  N-Content        0.0058     0.0106        0.023          0.0077       0.0062      0.0072     0.004
  (Nitrogen                                                                                    
  Content)                                                                                     
  ------------------------------------------------------------------------------------------------------------

Source: Environmental Protection Agency. 2003. Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2001. Chapter 5 (Table 5-20 and
page 5-23)

For each of the following crops, estimate the amount produced and the
fraction burned at least once during the year: corn, peanuts, soybeans,
barley, wheat, rice, sugarcane. Use the default data in Table 1.H.14 to
complete the equation below for each crop type. Sum the emissions from
each crop type for a total amount of N2O emissions from residue burning.

**N~2~O = Prod × Frac~burned~ × Ratio~residue:crop~ × DM × BE × CE ×
N-Content × EF~N2O~**

> **Where**
>
> **Prod = Annual production for a given crop type (metric tons)**
>
> **Frac~burned~ = Fraction burned annually for a given crop type**
>
> **Ratio~residue:crop~ = Ratio of residue to crop product volume**
>
> **DM = Dry Matter content of residues**
>
> **BE = Burning Efficiency (fraction of dry biomass exposed to**
>
> **fire that actually burns)**
>
> **CE = Combustion Efficiency (fraction of carbon in the fire**
>
> **that is oxidized completely to CO~2~)**
>
> **N-Content = Fraction of nitrogen in biomass**
>
> **EF~N2O~ = 0.007 (ton N~2~O per ton nitrogen)**

**1.H.4.2.1.1 Inference Using Default Emission Factors -- Methane
(CH~4~)**

**Rating: B**

Methane emissions from residue burning are estimated based on the amount
of crops produced, the fraction burned annually, and default data
provided in Table 1.H.14.

Use the same estimates for amount produced and fraction burned from the
nitrous oxide calculations (see 1.H.4.2.1 above). Calculate emissions
separately for corn, peanuts, soybeans, barley, wheat, rice, sugarcane
using the default data in Table 1.H.14 to complete the equation below.
Sum the emissions from each crop type for a total amount of CH~4~ from
residue burning.

**CH~4~ = Prod × Frac~burned~ × Ratio~residue:crop~ × DM × BE × CE ×
C-Content × EF~CH4~**

**Where:**

**Prod = Annual production for a given crop type (metric tons)**

**Frac~burned~ = Fraction burned annually for a given crop type**

**Ratio~residue:crop~ = Ratio of residue to crop product volume**

**DM = Dry Matter content of residues**

**BE = Burning Efficiency (fraction of dry biomass exposed to fire that
actually burns)**

**CE = Combustion Efficiency (fraction of carbon in the fire that is
oxidized completely to CO~2~)**

**C-Content = Faction of carbon in biomass**

**EF~CH4~ = 0.005 (ton CH4 per ton carbon)**

**1.H.4.2.2 Rice Cultivation**

Most rice grown in the United States is cultivated on shallow,
continuously flooded fields (EPA 2003), which results in emissions of
CH~4~. Anaerobic conditions in these waterlogged soils lead to the
decomposition of organic matter by CH~4~-emitting "methanogenic"
bacteria (IPCC 1997). CH~4~ from rice fields reaches the atmosphere
either by bubbling up through the soil, diffusion through water to the
surface, or diffusion through the vascular elements of plants. Soil
composition, texture, and temperature are important variables affecting
CH~4~ emissions from rice cultivation, as are the availability of carbon
substrate and other nutrients, soil pH, and partial pressure of CH~4~.

CH~4~ emissions from rice cultivation are limited to eight U.S. states:
Arkansas, California, Florida, Louisiana, Mississippi, Missouri,
Oklahoma, and Texas. In four of those states (Arkansas, Florida,
Louisiana, and Texas), the climate allows for cultivation of two rice
crops per season, the second of which is called a "ratoon crop." CH~4~
emissions from primary and ratoon crops should be estimated separately
because emissions are higher from ratoon crops (EPA 2003). The
methodology described in the next subsection does not apply to rice
grown on uplands that are not continuously flooded.

**1.H.4.2.2.1 Inference Using Default Emission Factors**

**Rating: B**

Methane emissions from rice can be estimated by multiplying the area of
land in rice cultivation by default emission factors. Two emission
factors (provided in Table 1.H.15) are needed, one for primary crops and
one for ratoon crops. This methodology provides only a rough estimate of
absolute emissions from rice production because it is based primarily on
area of land cultivated and does not capture the impacts of land
management practices. There is currently no methodology available to
assess the impacts of specific management practices on CH~4~ emissions
from rice, therefore this basic methodology is provided for reporters
wishing to establish emissions from this source category.

**CH~4~ = ∑ Ai \* EFi**

> **Where:**

**Ai = area of rice cultivation for either primary or ratoon crops
(hectares)**

**EFi = emission factor for primary or ratoon crops (kilograms CH~4~ per
hectare)**

**("i" indexes primary or ratoon crop)**

###### Table 1.H.15. Default Emission Factors for Methane Emissions from Rice Cultivation 

  --------------------------------- -------------------------------------
  **System**                        **Annual** **Emission** **Factor (kg
                                    CH~4~/ha)**

  Primary                           210

  Ratoon                            780
  --------------------------------- -------------------------------------

Source: Environmental Protection Agency. 2003. Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2001. Chapter 5 (page 5-14).

**1.H.4.2.2.2 Guidance on Improving Emission Factors**

The method to estimate methane emissions from rice farming contains no
site specific information and is highly uncertain, but is the currently
the best method available. Emissions estimates could be improved if
reporters developed site-specific emission factors. Site-specific
factors should be based on direct measurement or published research
studies on similar rice cultivation systems, and take into consideration
one or more of the following: regional rice cultivation practices;
variation in growing conditions over the course of a year; water
management regime and irrigation systems; application of organic
amendments such as manure, rice residue, and aquatic biomass; and soil
type (IPCC 2000).

Entities using other methods for estimating emissions from rice
cultivation must follow the guidelines for new methods provided in
Chapter 1, Part A, Section A.4.

**1.H.4.2.3 N~2~O from Agricultural Soils**

Amendments that add nitrogen to soils increase the production of N~2~O
because they provide additional nitrogen to the natural cycle of
nitrification and denitrification in soils. In nitrification, soil
microorganisms ("microbes") convert ammonium to nitrate through aerobic
oxidation (IPCC 1997). In denitrification, microbes convert nitrate to
dinitrogen gas by anaerobic reduction. During nitrification and
denitrification, soil microbes release N~2~O, which eventually reaches
the atmosphere. Commercial fertilizer, livestock manure, sewage sludge,
incorporation of crop residues, and cultivation of nitrogen-fixing
crops--- all add nitrogen to soils. Cultivating highly organic soils
also enhances mineralization of nitrogen-rich organic matter, making
more nitrogen available for nitrification and denitrification (EPA
2003). While N~2~O emissions in cultivated organic soils are not a
result of nutrient applications *per se*, they are included in this
category because the estimation techniques are inherently similar to
those used for the various nitrogen sources described above.

In addition to the direct emissions of N~2~O from soil nitrification and
denitrification, nitrogen may also be transported through groundwater
and run-off to other systems where it is later converted to N~2~O,
causing indirect emissions of N~2~O (IPCC 1997). Furthermore, some
applied nitrogen is volatilized into the atmosphere and subsequently
deposited back onto land, causing another indirect source of N~2~O.
Indirect emissions result from the application of commercial fertilizers
and livestock manure to soils.

**1.H.4.2.3.1. Inference Using Specific Activity Data and Default N~2~O
Emission Factor**

**Rating: B**

Emissions of N~2~O from agricultural soils originate from two sources:
nitrogen applications and cultivation of organic soils. Methods for
estimating emissions from those sources are provided below. Emissions
estimates for nitrogen applications and cultivation of organic soils
should be summed for a single estimate of N~2~O emissions from
agricultural soils.

[1.H.4.2.3.1.1 Emissions from Nitrogen Application and
Fixation]{.underline}

Nitrogen application can originate from several sources, including
commercial fertilizers, livestock manure, nitrogen fixation, and crop
residues. The first step in this method is to estimate the amount of
nitrogen applied to crops from each of these sources. Subsections below
provide guidelines for estimating the amount of nitrogen applied by each
source, which is used to estimate the amount of N~2~O emissions. Direct
emissions of N~2~O occur from all sources of nitrogen discussed, while
commercial fertilizers and manure applications also cause indirect
emissions.

Direct emissions from nitrogen application can be estimated by
multiplying a fraction of the total amount of nitrogen applied by a
fixed value of 2 percent.[^171] The fraction (fraction~direct~) reduces
the total amount of nitrogen applied to account for the portion assumed
lost through indirect emissions. Fractions by nitrogen source are given
in Table 1.H.16. Because there are only direct emissions from nitrogen
fixing crops and crop residues, the fraction for those sources of
nitrogen is 1.0.

**Direct N~2~O emissions (kg N~2~O) = N applied or fixed (kg N) \***

**fraction~direct~ \* 0.02 kg N~2~O /kg N**

Two types of indirect emissions are calculated separately for commercial
fertilizer and manure, as shown in the equations below. Volatilization
emissions of N~2~O are estimated by multiplying total nitrogen applied
by a fraction to obtain the portion volatilized (fraction~volatilized~),
and then by a fixed value of 1.6 percent.[^172] Run-off and leaching
emissions of N~2~O are estimated by multiplying the amount of total
nitrogen applied by a fraction to obtain the portion that runs off
and/or leaches into ground water (fraction~runoff~), and then by a fixed
value of 4 percent.[^173] Fractions by nitrogen source are given in
Table 1.H.16.

**Volatilization N~2~O (kg N~2~O) = N applied (kg N) \*
fraction~volatilized~ \* 0.016 kg N~2~O** **/kg N Run-off/leaching N~2~O
(kg N~2~O) = N applied (kg N) \* fraction~runoff~ \* 0.04 kg N~2~O**
**/kg N**

###### Table 1.H.16. Fractions by Nitrogen Source 

  ------------------------------------ ---------------------- --------------------------- ----------------------
  **Source**                           **fraction~direct~**   **fraction~volatilized~**   **fraction~runoff~**

  Nitrogen fixing crops and crop       1.0                    0.0                         0.0
  residues                                                                                

  Synthetic commercial fertilizers     0.9                    0.1                         0.3

  Organic commercial fertilizers and   0.8                    0.2                         0.3
  manure                                                                                  
  ------------------------------------ ---------------------- --------------------------- ----------------------

Source: Intergovernmental Panel on Climate Change. 1997. *Revised 1996
IPCC Guidelines for National Greenhouse Gas Inventories.* Reference
Manual (Volume 3). Chapter 4: Agriculture. Paris, France (table 4-24 and
page 4.89).

1.H.4.2.3.1.1.1 Estimating the Amount of Nitrogen in Crop Applications

1.H.4.2.3.1.1.1.1 *Commercial Fertilizer* Reporters should determine the
amount of fertilizer applied to crops, in kilograms (kg), and multiply
that amount by the fertilizer's nitrogen content (given as a percent of
nitrogen in product information) to determine the N applied (kg N). This
should be done separately for synthetic and non-manure organic
fertilizers.

1.H.4.2.3.1.1.1.2 *Livestock Manure* Determine the amount of livestock
waste (manure and urine) applied to fields from different livestock
types (generally this will be categorized as pounds (lbs.) of waste
applied on a wet basis). Multiply the amount applied by the appropriate
percent nitrogen given in Table 1.H.17. Percent nitrogen values in Table
1.H.17 are based on the percent of nitrogen in waste relative to the
total wet weight of waste, as excreted (USDA 1996a). Convert "lbs" of
nitrogen to "kg" before using the equations above.

###### Table 1.H.17. Nitrogen Content of Manure for Broad Livestock Classes 

  ----------------------------------- -----------------------------------
  **Livestock** **Manure**            **Percent N^1^**

  Dairy                               0.5%

  Beef                                0.5%

  Swine                               0.7%

  Poultry                             2.5%

  Sheep                               1.1%

  Horse                               0.6%
  ----------------------------------- -----------------------------------

Source: United States Department of Agriculture. 1996. *Agricultural
Waste Management Field Handbook.* Chapter 4. (Tables 4-5, 4-8, 4-11,
4-14, 4-18, and 4-19), web site:
[www.wcc.nrcs.usda.gov/awm/awmfh.html](http://www.wcc.nrcs.usda.gov/awm/awmfh.html).

1\. In the above tables, divide value for "N" by value for "Weight". For
some species, values in table 1.H.17 reflect an average percent of
nitrogen computed over several livestock groups.

1.H.4.2.3.1.1.1.3 *Nitrogen Fixation* For each leguminous crop type
listed in Table 1.H.18, determine the annual amount of crop produced and
use the equation below and corresponding coefficients in Table 1.H.18 to
estimate kg N for use in the Direct N~2~O emissions calculation in
subsection 1.H.4.2.3.1.1.

**kg N = Prod \* N~conversion~**

> **Where:**
>
> **Prod = amount of crop produced/harvested (kg)**

**N~conversion~ = fraction of nitrogen in harvest and residue biomass
per kg**

> **of crop harvested**

###### Table 1.H.18. Default Nitrogen Conversion Factors for Leguminous Crops 

  ----------------------------------- -----------------------------------
  **Crop**                            **N~conversion~ (kg N / kg
                                      harvested)**

  Soybeans                            0.062

  Peanuts                             0.018

  Dry edible beans                    0.014

  Dry edible peas                     0.014

  Austrian winter peas                0.014

  Lentils                             0.014

  Wrinkled seed peas                  0.014

  Alfalfa                             0.062

  Forage species (other than alfalfa) 0.067
  ----------------------------------- -----------------------------------

Source: Environmental Protection Agency. 2003. *Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2001.* Annex N. Table N-6.

1.H.4.2.3.1.1.1.4 *Crop Residue* The method for estimating the amount of
nitrogen in crop residues is essentially the same as for estimating the
amount of nitrogen in legumes, with one exception: only the nitrogen in
the residue fraction of plant biomass is estimated. Use the coefficients
provided in Table 1.H.19 to estimate the amount of nitrogen in crop
residues.

**kg N = Prod \* N~conversion~**

> **Where:**

Prod = amount of crop produced/harvested (kg)

**N~conversion~ = fraction of nitrogen in residue biomass per kg of
crop**

> **harvested**

###### Table 1.H.19. Default Ratios for Nitrogen Content for Major Crops 

  -------------- --------------------------------------------------------
  **Crop**       **N~conversion~ (kg N / kg harvested)**

  Corn           0.005

  Wheat          0.007

  Barley         0.009

  Sorghum        0.014

  Oats           0.008

  Rye            0.007

  Millet         0.009

  Rice           0.009
  -------------- --------------------------------------------------------

Environmental Protection Agency. 2003. *Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2001.* Annex N, Table N-6.

[1.H.4.2.3.1.2 Emissions from Cultivation of Organic Soils]{.underline}

Standard soil taxonomy classifies organic soils as "histosols."[^174] To
estimate annual N~2~O emissions from cultivated organic soils, estimate
the area of organic soils cultivated within the entity and determine
whether the entity is in a temperate or subtropical climate region. Note
that most of the United States is considered temperate, except for parts
of the Gulf coast. See Map 1.H.1 below in the subsection titled
"Characterizing the Land Base." Multiply the area by the appropriate
emissions factor in Table 1.H.20.

**N~2~O = ∑ A~i~ \* EF~i~**

> **Where:**

**A~i~ = area of organic soils cultivated in climate region i (ha)**

**EF~i~ = emission factor climate region i (kg N~2~O/ha)**

###### Table 1.H.20. Emission factors for N~2~O from organic soil cultivation 

  ----------------------------------- -----------------------------------
  **Region**                          **Emission factor (kg N~2~O/ha)**

  Temperate                           12.57

  Subtropical                         18.86
  ----------------------------------- -----------------------------------

Sources:

1\. Environmental Protection Agency. 2003. *Inventory of U.S. Greenhouse
Gas Emissions and Sinks: 1990-2001.* Chapter 5. pg. 5-17.

2\. Intergovernmental Panel on Climate Change. 2000. *Good Practice
Guidance and Uncertainty Management in National Greenhouse Gas
Inventories.* Chapter 4. IPCC National Greenhouse Gas Inventories
Programme Technical Support Unit. Japan Table 4.17, pp. 4.60. Values in
Table 4.17 are in units of, N~2~O-N. To convert to units of N~2~O use
the formula: N~2~O = N~2~O-N \* 44/28

Emissions of nitrous oxide from agricultural soils, both direct and
indirect, are greatly affected by site-specific factors such as soil
texture, soil moisture, precipitation and atmospheric conditions. Thus,
estimates obtained with this methodology are highly uncertain when
applied to specific situations.

**1.H.4.2.3.2 Additional Resources**

Estimating or measuring nitrous oxide emissions from agricultural soils
is a developing science and methodologies and models are changing
rapidly. Direct field-scale measurements can be accomplished by either
soil chamber or micrometeorological methods. At present both approaches
are expensive and difficult to execute. As a result, use of direct
field-scale measurement methods are typically limited to research
applications. Additional information on these measurement techniques can
be found in Laville, *et al.*, 1997 and Hatfield and Baker, 2004.

Two models are available for acquiring default values for nitrous oxide
emissions from agricultural soils. The Nitrate Leaching and Economic
Analysis Package (NLEAP) is a field-scale computer model developed to
provide a rapid and efficient method of determining potential nitrate
leaching and nitrous oxide emissions associated with agricultural
practices. It combines basic information about on-farm management
practices, soils, and climate, and then translates the results into
projected budgets for nitrogen.[^175]

The second model option is the DAYCENT model. DAYCENT is a dynamic daily
time-step model that simulates exchanges of carbon, nitrogen (N), and
phosphorus (P) between the atmosphere, soil, and plants that result from
plant growth and events such as fire, grazing, cultivation, harvest, and
organic matter or fertilizer additions. The EPA, USDA's Agriculture
Research Service, and the Natural Resources Ecology Laboratory at
Colorado State University, are working together to evaluate the utility
of the DAYCENT model in providing estimates of N~2~O emissions related
to agricultural soil management practices.

All practices designed to reduce emissions should be consistent with the
practice standard and specifications for Nutrient Management (590).
Entities developing site-specific measurements or model-based estimates
for nitrous oxide emissions from soils must follow the guidelines for
new methods provided in Chapter 1, Part A, Section A.4.

**1.H.4.2.4 Lime Applications**

Lime, in the form of limestone or dolomite, is often added to
agricultural soils to reduce acidic conditions. Lime contains carbonate
compounds that release carbon dioxide through the bicarbonate
equilibrium reaction when added to soils (IPCC 1997). The amount of
emissions from this source is uncertain \-- a single, simple approach to
calculating the amount is provided below.

**1.H.4.2.4.1 Inference Using Default Emission Factors**

**Rating: B**

carbon dioxide emissions from limestone and dolomite applications can be
estimated from the amount of lime applied. The amount applied, in metric
tons, over the course of a year is multiplied by the emission factors
provided in Table 1.H.21. Separate factors are provided for limestone
and dolomite. Emissions from limestone and dolomite are totaled to yield
an entity estimate of emissions from lime.

**CO~2~ = ∑ Lime~i~ \* EF~i~**

> **Where:**
>
> **Lime~i~ = amount of lime applied as limestone or dolomite (metric
> tons)**
>
> **EF~i~ = emission factor limestone or dolomite (tons CO~2~/ton
> applied)**

###### 

###### Table 1.H.21. Emission Factors for Limestone and Dolomite Applications

  ----------------- ------------------------------------------------------
  **Application**   **Emission factor (tons CO~2~E / ton applied)**

  Limestone         0.44

  Dolomite          0.48
  ----------------- ------------------------------------------------------

Source: Environmental Protection Agency. 2005. Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2003. Chapter 7 (page 245,
multiply values on page 245 by 3.67 to convert emissions from units of
carbon to units of carbon dioxide).

##### 1.H.4.3 Agricultural Soil Carbon Emissions and Sequestration 

Entities can estimate and report carbon dioxide emissions and
sequestration associated with cropping practices and grazing land
management. Carbon dioxide emissions and sinks in soils are related to
how much organic carbon is stored in soils (IPCC 1997). Change in the
organic carbon content of soil is based on the balance between carbon
inputs (e.g., atmospheric carbon dioxide fixed as carbon in plants
through photosynthesis) and losses (e.g., decomposition of soil organic
matter). The net balance of carbon dioxide uptake and loss in soils is
affected by soil characteristics and climate. Land use and management
also affect the net balance of carbon dioxide through modifying inputs
and rates of decomposition. Changes in agricultural practices such as
clearing, drainage, tillage, crop selection, grazing, crop residue
management, fertilization, irrigation, and flooding can modify both
organic matter inputs and decomposition, and thereby result in a net
flux of carbon dioxide to or from soils.

Most agricultural soils contain comparatively low amounts of organic
carbon as a percentage of total soil mass, typically in the range of 0.5
to 3.0 percent for soil between the surface and a depth of 25 to 30
centimeters (cm). However, on an area basis, this amount of carbon
typically exceeds the amount stored in vegetation in most ecosystems
(including forests). Conversion of native ecosystems to agricultural
uses has resulted in large losses of soil carbon \-- as much as 30 to 50
percent or more (Haas, *et al.* 1957, Schlesinger 1986). After many
decades of cultivation, however, most soils have likely stabilized at
lower carbon levels or are increasing their organic matter levels as a
result of increasing crop productivity (providing more residues), less
intensive tillage, and other changes in agricultural management
practices (Paustian, *et al.* 1997a,b; Allmaras, *et al.* 2000; Follett
2001). Changes in land-use or management practices that result in
increased organic inputs or decreased oxidation of organic matter (e.g.,
taking cropland out of production, improved crop rotations, cover crops,
application of organic amendments and manure, and reduction or
elimination of tillage) will result in a net accumulation of soil
organic carbon until a new equilibrium is achieved.

Organic soils (histosols) contain more than 20 to 30 percent organic
matter by weight. These soils form under waterlogged conditions, which
slows decomposition of plant residues. When organic soils are drained
and cultivated the rate of decomposition and carbon dioxide emissions
are greatly accelerated. Carbon loss from cultivated organic soils can
continue over long periods of time because of the depth and richness of
the organic layers. Unless restored to undrained, anaerobic conditions,
cultivated organic soils remain a net source of carbon dioxide.

Carbon dioxide is also fixed as organic carbon in perennial biomass
(e.g., trees, shrubs, and grasses) through photosynthesis. This carbon
remains stored in biomass until released by decomposition. Agroforestry
practices such as establishing windbreaks and riparian forest buffers
can lead to carbon sequestration in both soil and biomass. Methods for
estimating carbon fluxes in agroforestry systems are provided in Part I
of this Chapter. Carbon fluxes on forestlands within the boundaries of
agricultural entities also should be estimated following the guidance in
Part I.

**1.H.4.3.1 Characterizing the Land Base**

The methods below require entities to first characterize the croplands
and pasture/grazing lands on which they are reporting by soils,
management practices, and climate regions. At the broadest level,
entities will need to classify croplands and pasture/range lands into
organic and mineral soils. Emissions estimates for cultivated mineral
soils (i.e., mineral soils on croplands) require soils to be further
subdivided into general classes of soil as defined in the methods below.

Similar to livestock emissions estimates, an entity may need to
determine its climate region(s) to employ the most specific default
emission/sequestration factors available. The regions specified in the
default tables are shown in Map 1.H.1.

**Map 1.H.1**

![](media/image1.jpeg){width="5.002083333333333in"
height="4.302777777777778in"}

Three methods are provided below for estimating carbon dioxide fluxes on
mineral agricultural soils. A single, simple method is provided to
estimate emissions of carbon dioxide from organic soils. Reporters will
need to estimate and report carbon dioxide fluxes on mineral soils
separately from carbon dioxide emissions on organic soils.

**1.H.4.3.2 Carbon Dioxide Fluxes on Mineral Soils**

**1.H.4.3.2.1 Inference Using Default Emission and Sequestration
Factors**

**Rating: C**

This approach estimates carbon dioxide emissions and sequestration
separately, then sums the two to obtain a net balance of carbon dioxide
emissions/sequestration in soils. Methods for estimating emissions and
sequestration are provided separately below. By convention,
sequestration is considered a negative emission and is represented with
a negative number.

[1.H.4.3.2.1.1 Emissions]{.underline} Conventional tillage disturbs the
soil and accelerates the oxidation of carbon compounds in it. If tillage
practices have been in place for a significant length of time (more than
20 years) it is likely that the soil carbon is in equilibrium and is
neither a source nor a sink of carbon. When perennial vegetation is
initially plowed, soil carbon loss is rapid. In general, about 40
percent of the total soil carbon is lost in the first few years after
initial cultivation.

Reporters should determine the area of mineral soils under conventional
tillage. Most agricultural entities will be contained within a single
climate region and should use the appropriate regional factors. Separate
calculations for each climate region are necessary for those entities
owning agricultural land in more than one climate region.

The next step is to estimate carbon dioxide losses from mineral soils.
Emissions are assumed to occur only in the first year of cultivation.
Emissions are estimated by multiplying the area cultivated by the
emissions factors in Table 1.H.22. The emissions factors account for a
40 percent loss of soil carbon. After the first year of cultivation, it
should be assumed there are no additional losses of carbon dioxide. It
is important to note that cropland will often have been under
cultivation for several years before the base period of the Voluntary
Reporting of Greenhouse Gases Program. In these cases, reporters should
not report carbon dioxide emissions from soils.

###### Table 1.H.22: CO~2~ Emissions Factors by Soil Type After First Year of Cultivation 

+---------+----------------+------+------+------+------+------+-----+
| **Soil  |                | **C  |      |      |      |      |     |
| Type**  |                | lima |      |      |      |      |     |
|         |                | te** |      |      |      |      |     |
|         |                | **R  |      |      |      |      |     |
|         |                | egio |      |      |      |      |     |
|         |                | ns** |      |      |      |      |     |
+---------+----------------+------+------+------+------+------+-----+
| **IPCC  | **USDA         | **Co |      | **Wa |      | **S  |     |
| Soil**  | Taxonomic Soil | ld** |      | rm** |      | ubtr |     |
|         | Orders**       | *    |      | *    |      | opic |     |
| **Categ |                | *Tem |      | *Tem |      | al** |     |
| ories** |                | pera |      | pera |      |      |     |
|         |                | te** |      | te** |      |      |     |
+---------+----------------+------+------+------+------+------+-----+
|         |                | **D  | *    | **D  | *    | **D  | **M |
|         |                | ry** | *Moi | ry** | *Moi | ry** | ois |
|         |                |      | st** |      | st** |      | t** |
+---------+----------------+------+------+------+------+------+-----+
|         |                | **   |      |      |      |      |     |
|         |                | tons |      |      |      |      |     |
|         |                | CO   |      |      |      |      |     |
|         |                | ~2~/ |      |      |      |      |     |
|         |                | ha** |      |      |      |      |     |
+---------+----------------+------+------+------+------+------+-----+
| High    | Vertisols,     | 62   | 95   | 54   | 75   | 62   | 84  |
| clay    | mollisols,     |      |      |      |      |      |     |
|         | inceptisols,   |      |      |      |      |      |     |
| a       | aridisols, and |      |      |      |      |      |     |
| ctivity | high base      |      |      |      |      |      |     |
| mineral | status         |      |      |      |      |      |     |
| soils   | alfisols       |      |      |      |      |      |     |
+---------+----------------+------+------+------+------+------+-----+
| Low     | Ultisols,      | 66   | 76   | 37   | 59   | 57   | 69  |
| clay    | oxisols,       |      |      |      |      |      |     |
|         |                |      |      |      |      |      |     |
| a       | acidic         |      |      |      |      |      |     |
| ctivity | alfisols,      |      |      |      |      |      |     |
|         |                |      |      |      |      |      |     |
| mineral | and many       |      |      |      |      |      |     |
| soils   | entisols       |      |      |      |      |      |     |
+---------+----------------+------+------+------+------+------+-----+
| Sandy   | Any soils with | 35   | 59   | 23   | 44   | 48   | 73  |
| soils   |                |      |      |      |      |      |     |
|         | greater than   |      |      |      |      |      |     |
|         | 70%            |      |      |      |      |      |     |
|         |                |      |      |      |      |      |     |
|         | sand and less  |      |      |      |      |      |     |
|         | than           |      |      |      |      |      |     |
|         |                |      |      |      |      |      |     |
|         | 8% clay (often |      |      |      |      |      |     |
|         |                |      |      |      |      |      |     |
|         | Entisols)      |      |      |      |      |      |     |
+---------+----------------+------+------+------+------+------+-----+
| V       | Andisols       | 182  | 167  | 182  | 182  | 182  | 188 |
| olcanic |                |      |      |      |      |      |     |
| soils   |                |      |      |      |      |      |     |
+---------+----------------+------+------+------+------+------+-----+
| Spodic  | Spodosols      | 126  | 109  | 126  | 157  | 126  | 126 |
| soils   |                |      |      |      |      |      |     |
+---------+----------------+------+------+------+------+------+-----+
| Aquic   | Soils with     | 126  | 131  | 70   | 75   | 92   | 70  |
| soils   | aquic          |      |      |      |      |      |     |
|         |                |      |      |      |      |      |     |
|         | suborder       |      |      |      |      |      |     |
+---------+----------------+------+------+------+------+------+-----+

Source: Environmental Protection Agency. 2003. Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2001. Annex P. Table P.2 on
page P-2. Values in Table P.2 were first multiplied by 3.67 to convert
carbon units to CO~2~ equivalents and then multiplied by 0.4 (see note
below).

Note: Factors were calculated as 40 percent of the carbon stocks
published in EPA 2003, which were estimated from pedon data in the
database of the National Soil Survey Center, USDA NRCS (1997) for the
top 30 cm of the soil profile.

[1.H.4.3.2.1.2 Sequestration]{.underline} Reducing soil disturbance
and/or increasing plant productivity will increase soil carbon. Table
1.H.23 provides sequestration coefficients for soil carbon increases.
Increases will occur annually for a period of years following the
adoption of conservation practices. The sequestration rates in Table
1.H.23 are the midpoint of ranges for the sequestration potential of
agricultural management practices published in Follett (2001) and Lal,
*et al.* (1998).

The disruption of practices listed in Table 1.H.23 can result in the
cessation of carbon sequestration and even cause a rapid loss of soil
carbon. For example, increases in soil carbon gained from using reduced
tillage for many years will be rapidly lost if a farmer reverts to
conventional tillage.

Most of the research studies on which the sequestration factors are
based were conducted in agricultural systems that receive between 10 and
50 inches of precipitation per year---the greater the rainfall, the
greater potential to sequester carbon. For instance, years with
less-than-average precipitation can result in reduced sequestration of
carbon, or even losses of soil carbon if the drought is sufficiently
severe. Typically, if a management regime is in place for an extended
period of time (approximately 20 years), soil carbon will equilibrate
and the quantity will not change unless there is a change in inputs,
tillage practices, or weather.

The first step in quantifying sequestration levels is to estimate the
amount of land on which each of the management practices in Table 1.H.23
is in use. For lands on which these practices have been in use for less
than 20 years, multiply the land area by the sequestration rate
provided. This sequestration rate can be assumed each year for 20 years
as long as the management practice is implemented continuously. Twenty
years after the adoption of a practice (assuming that the practice was
implemented continuously for 20 years), no annual changes in soil carbon
stocks should be reported. If no till, mulch till, or ridge till
practices cease at any point and are replaced by conventional till,
carbon emissions occur and are equal to the gains recorded up to that
point as a result of no till, mulch till, or ridge till.

Carbon dioxide emissions from agricultural soils are affected by a
variety of site specific factors beyond the control of managers,
specifically precipitation, soil temperature, soil texture and soil
moisture. The default estimates provided in this method do not account
for site-to-site variations and are highly uncertain.

###### Table 1.H.23. Potential Rates of Carbon Sequestration 

  -------------------------------------------------------------------------
  **Practice**              **Description**          **Sequestration factor
                                                     (kg CO~2~/ha/yr)**
  ------------------------- ------------------------ ----------------------
  Improved rangeland        Grazing management^1^,   300
  management                Riparian management^2^,  
                            Prescribed burning^3^    

  Improved pastureland      Applying nutrients       900
  management\--fertilizer   consistent with plant    
  application               uptake requirements^4^   

  Improved pastureland      Planting species adapted 730
  management\--improved     to soils, climate and    
  forage species            grazing needs^5^         

  Improved grazing          Rotational grazing,      2,900
  management on pasture     improved forage          
                            systems^6^               

  Restoration of mined      Establishing vegetation  6,400
  lands                     on mined soils^7^        

  Conversion of cropland to Establishing adapted     2,900
  improved pasture          species on formerly      
                            cropped land^8^          

  Conversion of cropland to Establishing native      2,800
  natural vegetation        vegetation on formerly   
                            cropped land^9^          

  Conversion from           Leaving crop residue on  1,300
  conventional to no till   soil surface, planting   
  and maintaining no till   in narrow bands^10^      
  for 20 years                                       

  Conversion from           Leaving adequate residue 900
  conventional to mulch     on soil surface through  
  till, or ridge till and   out the year^11^         
  maintaining mulch or                               
  ridge till for 20 years                            
  -------------------------------------------------------------------------

Source: Sequestration factor reflect midpoints of ranges published in
Follett 2001 and Lal, *et al*. 1998

1\. Consistent with Prescribed Grazing Standard and Specification
(528).\
2. Consistent with Riparian Cover Standard and Specification (390).\
3. Consistent with Prescribed Burning Standard and Specification (338).\
4. Consistent with Nutrient Management Standard and Specification
(590).\
5. Consistent with Pasture and Hayland Planting Standard and
Specification (512).\
6. Consistent with Prescribed Grazing Standard and Specification (528).\
7. Consistent with Abandoned Land Reconstruction Mined Land (543).

8\. Consistent with Pasture and Hayland Planting Standard and
Specification (512).\
9. Consistent with Pasture and Hayland Planting (512), Tree and Shrub
Planting (612), Early Successional Habitat Establishment (647), Range
Planting (520).

10\. Consistent with Residue Management Standard and Specification
(329).

**1.H.4.3.2.2 Model-based Estimates of CO~2~ Flux on Mineral Soils**

**Rating: A or B**

USDA's Natural Resources Conservation Service, in collaboration with
researchers at the Natural Resources Ecology Laboratory at Colorado
State University, developed the CarbOn Management Evaluation Tool
(COMET-VR) to help entities obtain default estimates of annual soil
carbon fluxes for purposes of reporting under the 1605(b) Voluntary
Reporting of Greenhouse Gases Program. COMET-VR is a web-based
calculation tool that allows users to estimate changes in mineral soil
carbon storage on cultivated lands for most regions and cropping systems
prevalent in the United States.

The COMET-VR system has a simple interface where users provide basic
information about a parcel of land including soil characteristics and
land management and COMET-VR provides estimates of annual soil carbon
flux. COMET-VR also produces an uncertainty analysis of the soil carbon
flux estimates to help reporters assess the precision of these values.
The measure associated with this analysis is important to reporters
because it indicates whether a carbon flux measure obtain using COMET-VR
is rated as an A or a B method. When the model inputs closely match
actual conditions on the entity, the corresponding uncertainty estimate
will be low. For uncertainty estimates less than or equal to 15 percent,
COMET-VR may be treated as an A rated method. When model inputs are not
a good match for actual conditions on the entity, the corresponding
uncertainty estimate will be high. For uncertainty estimates greater
than 15 percent, COMET-VR should be treated as a B rated method.

Specific information requirements and guidance on using COMET-VR to
estimate and report soil carbon fluxes for the 1605(b) Program are
detailed in the Appendix to Chapter 1, Part H of the Technical
Guidelines. This Appendix also provides the rationale for, and detailed
description of, the methods used to estimate soil carbon flux for
different agricultural practices and regions in the United States.

COMET-VR is available online at the website:
<http://www.cometvr.colostate.edu/>.

Entities developing agricultural soil carbon flux estimates using other
models must follow the guidance on new methods in Chapter 1, Part A,
Section A.4.

**1.H.4.3.2.3 Direct Measurement of Mineral Soil Carbon Stocks**

**Rating: A or B**

Periodic soil carbon sampling can provide highly reliable estimates of
carbon stocks and fluxes for particular fields. Entities wishing to
employ this approach should review the protocols outlined in the
Australian Greenhouse Office Technical Report No. 14 (Australia 2000),
the USDA NRCS Soil Survey Laboratory Methods Manual, Version 4 (USDA
NRCS 2004)[^176], and Chapters 9 and 10 in "Assessment Methods for Soil
Carbon" by Lal, *et al.* (2001). These documents provide standardized
techniques for collecting, preparing, and analyzing soil samples. All
laboratory analysis must be performed consistent with technical
standards described in the Soil Science Society Book Series Numer 5
(Part 1, 1986, ed A. Klute; Part 2, 1994, ed. R.W. Weaver, S. Angle, and
P. Bottomly; Part 3, 1996, ed. D.L. Sparks; and Part 4, 2002, ed. J.H.
Dane and G.C. Topp).

Developing an efficient sampling system requires attention to the
following basic steps (Smith 2001):

-   Determine an acceptable level of uncertainty or error (see below for
    a discussion on uncertainty levels).

-   Make a preliminary determination of the amount and structure of
    variability inherent within a population and then stratify samples
    to minimize the variation.

-   Adjust sampling protocols to optimize the cost in relation to error.

*Stratifying samples to estimate soil carbon*: At a minimum, fields or
groups of fields should be stratified by the following:

-   Soil map unit (component if map unit is an association) using
    National Cooperative Soil Survey Report for the area. Soil surveys
    can be obtained from the local NRCS field office or at the USDA
    website: http://soils.usda.gov/

-   Management system (cropping system, tillage practice)

-   Topographic position (ridge, slope, toe, aspect)

-   Microtopography (depression, hummock)

Within each stratum, sample points may be randomly placed or
systematically distributed in a grid pattern. Use the equation below to
determine the appropriate number of samples to meet a desired level of
statistical error. In general, increasing the number of samples will
decrease the error. Several iterations may be necessary to determine the
appropriate number of samples.

**n = (t \* s/E)^2\ ^**

> **Where:**

**n = number of samples**

> **t = estimate of the statistical distribution of the variance for a
> given**
>
> **degrees of freedom and confidence interval, taken from table of**
>
> **Student's t distribution**

**s = standard deviation of the soil samples**

> **E = desired confidence interval**

In this equation, *n* is the number of samples required and *t* is a
value taken from a table of the Student's t distribution (an estimate of
the statistical distribution of the variance for a given degrees of
freedom and confidence interval). The standard deviation of the soil
samples (*s*) and the half width of the desired confidence interval
(*E*) must be approximated to make a preliminary estimate for *n*.
Approximations of *s* and *E* can be derived from published analyses of
soil samples.

The value for *t* is taken from a standard table of values available in
most statistical textbooks and depends on a given sample size. Begin
with an initial approximation of the sample size and use this to choose
a t-value. Estimate *n* using this t-value and the equation above. The
solution for *n* is reached when the sample size used to choose a
t-value matches or is slightly greater than the *n* calculated from the
equation. More detail can be found in most statistical textbooks on
using this approach to determine the sample size needed to estimate a
mean value within a given level of certainty.

Samples may be collected in two different ways: randomly within a
stratum during succeeding sampling dates, or in time separate pairs
where pairs of points are relocated in succeeding sampling dates to
determine change (Kimble, *et al.* 2001). In either case, the estimate
is of change in carbon stock over time. To insure consistency, sampling
should be conducted at the same time of year.

*Extracting samples:* To estimate changes in soil carbon, a soil sample
should be extracted to a depth defined by the A horizon in the map unit
description of the Soil Survey (soil surveys can be obtained from the
local NRCS field office or at the USDA web site:
<http://soils.usda.gov/>.

As a default, soil may be extracted to a depth of 25 cm. Extraction of
samples is best accomplished with a sampling tube.

*Estimating the carbon in a sample:* Only certified laboratories can
estimate the organic carbon content of soil samples. The local land
grant university is usually the best provider of this service. Most
laboratories report on the basis of percent carbon in the sample.

*Estimating the carbon in a field or fields:* The amount of carbon in a
field or fields at any point in time should be expressed as metric tons
carbon (C) per hectare to a consistent depth. Extrapolating from a point
to a field level requires converting the percent C in a sample to an
absolute amount per volume of soil. Soil volume (expressed as bulk
density) can change as carbon changes, thus it is best to have estimates
of bulk density made by the same laboratory selected to estimate soil
organic carbon.

Bulk density of soil is usually expressed as grams per cubic centimeter
(g/cc). Multiplying the weight of the soil per volume (g/cc) by depth
(cm) of the soil sampled by 1000 (cm^2^/m^2^) will yield weight of soil
per square meter (g/m^2^). Dividing by 100 will yield MT soil/ha to
depth (MT = metric tons). Determining absolute carbon requires then
multiplying by the percent C in a sample. The result should be MT C/ha
multiplied by the number of ha in each strata. Summing over all strata
should yield the total amount of carbon.

*Frequency of sampling:* Changes in soil carbon occur relatively slowly.
It is difficult to detect small changes (less than 1 MT C/ha) over any
time period. The time separating sampling dates to assess reportable
changes in soil carbon should not be less than 3 years and not more than
5 years. Estimates of changes in soil carbon pools using this method can
have low uncertainty. The use of statistical techniques allows for the
calculation of a standard error of the mean that is a quantitative
estimate of uncertainty.

**1.H.4.3.3 CO~2~ Emissions on Cultivated Organic Soils**

As in mineral soils, both carbon dioxide emissions and sequestration may
occur in organic soils, although as long as organic soils are cultivated
they continue to be a net source of carbon dioxide emissions. Emissions
may be reduced through practices such as water table management and
taking lands out of cultivation. Once taken out of cultivation, it is
likely that soil carbon stocks rebuild gradually over time, although
reliable information on annual rates of carbon sequestration in organic
soils taken out of cultivation is not currently available. This method
therefore takes into consideration emissions only from organic soils,
and the method below provides a rough estimate of emissions from organic
soil cultivation. While management practices such as water table
management are believed to reduce carbon dioxide emissions, the best
available methods do not take management impacts into consideration.
This methodology will only capture changes in carbon dioxide emission
from organic soils that occur when lands are taken out of production.

**1.H.4.3.3.1 Inference Using Default Emissions Factors**

**Rating: B**

Once organic soils are put under cultivation, carbon losses typically
continue until the organic soil layer has been completely depleted (IPCC
1997). carbon dioxide losses are thus assumed to continue after soils
are initially cultivated and are reported each year. To estimate carbon
dioxide losses from organic soils, divide the area of organic soils into
those on which crops are produced and those used for pasture; include
pasturelands in the estimate if they were cultivated and planted with
forage species (e.g., grasses and legumes) and used for grazing. Assume
zero emissions from uncultivated pastures on organic soils. Multiply the
area of organic soils by the appropriate emission factors provided in
Table 1.H.24.

###### Table 1.H.24. Emission Factors for CO~2~ Emissions from Cultivated Organic Soils 

+----------------------------+-------------------+---------------------+
| **Climate Region**         | **Cropland**      | **Cultivated        |
|                            |                   | Pastures**          |
|                            | **(tons           |                     |
|                            | CO~2~/ha-yr)**    | **(tons             |
|                            |                   | CO~2~/ha-yr)**      |
+----------------------------+-------------------+---------------------+
| Cold temperate, dry and    | 41.10             | 10.28               |
| moist                      |                   |                     |
+----------------------------+-------------------+---------------------+
| Warm temperate, dry and    | 51.38             | 12.85               |
| moist                      |                   |                     |
+----------------------------+-------------------+---------------------+
| Subtropical, dry and moist | 51 .38            | 12.85               |
+----------------------------+-------------------+---------------------+

Source: Environmental Protection Agency. 2003. *Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2001*. Annex P (Table P.6 on
page P-5). Multiply values in Table P-6 by 3.67 to convert from units of
carbon to units of CO~2~.

**1.H.4.3.3.2 Direct Measurement of Organic Soil Carbon Stock Change**

**Rating: A or B**

Carbon dioxide emissions from organic soils can be estimated by
measuring the annual changes in soil carbon stocks. Cultivated organic
soils typically lose carbon annually in the form of carbon dioxide
emissions. Annual changes in soil carbon stocks can be measured with a
systematic sampling method applied in the field. Such field methods draw
on the soil sampling methods described in subsection 1.H.4.3.2.3 to
estimate initial carbon stocks. In addition, physical soil carbon losses
are measured by establishing a benchmark and measuring annual changes
relative to that benchmark.

Carbon in organic soils should be measured similarly to mineral soils
with the exception of depth of measurement. Organic soils should be
sampled to a depth of 1m or to the water table if less than 1m. Just as
in mineral soils, C content per volume of soil should be determined by
calculation of bulk density and adjustment for area extent. If
cultivated organic soils are converted to wetlands by abandoning
cultivation, reestablishing native vegetation and reestablishing the
water table, benchmark conditions should be adjusted to calculate soil C
in a similar volume of soil as post watering conditions.

The sampling method described above can be used to develop an A or B
rated estimate of carbon dioxide emissions from organic soils. Sampling
methods have the potential to yield relatively certain estimates of
changes in carbon stocks on organic soils. As with the mineral soil
sampling method, estimates derived from a sampling program for organic
soils should receive an A rating when the associated uncertainty levels
are less than or equal to 15 percent. The use of a sampling program,
however, does guarantee a high level of certainty. Therefore if
associated uncertainty levels are greater than 15 percent the estimates
should be rated a B.

###### Table 1.H.25. Metabolizable Energy (ME) by Feed Type (for Enteric Fermentation)

  ------------------------------------------------------------------------
  **Feed   **Feed Type**                   **Mcal/kg**
  No.**                                    
  -------- ------------------------------- -------------------------------
  101      Bahiagrass, 30% Dry Matter      1.95

  102      Bahiagrass, Hay                 1.84

  103      Bermudagreass, Late Vegetative  1.77

  104      Brome Hay, Pre-Bloom            2.17

  105      Brome Hay, Mid-Bloom            2.02

  106      Brome Hay, Late Bloom           1.99

  107      Brome Hay, Mature               1.92

  108      Fescue, Meadow Hay              2.02

  109      Fescue Alta, hay                1.99

  110      Fescue K31, Hay                 2.21

  111      Fescue K31, Hay, Full Bloom     2.10

  112      Fescue K31, Mature              1.59

  113      Napiergrass, Fresh 30 day DM    1.99

  114      Napiergrass, Fresh 60 day DM    1.92

  115      Orchardgreass, Hay, Early Bloom 2.35

  116      Orchardgreass, Hay, Late Bloom  1.95

  117      Pangolagrass, Fresh             1.99

  118      Red Top, Fresh                  2.28

  119      Reed Canarygrass, Hay           1.99

  120      Ryegrass, Hay                   2.31

  121      Sorghum-Sudan, Hay              2.03

  122      Sorghum-Sudan, Pasture          2.35

  123      Sorghum-Sudan, Silage           1.99

  124      Timothy Hay, Late Vegetative    2.24

  125      Timothy Hay, Early Bloom        2.13

  126      Timothy Hay, Mid Bloom          2.06

  127      Timothy Hay, Full Bloom         2.02

  128      Timothy Hay, Seed Stage         1.70

  129      Wheatgrass, crest. Hay          1.92

  135      Grass Pasture, Spring           2.68

  136      Grass Pasture, Summer           2.42

  137      Grass Pasture, Fall             1.92

  138      Mix Pasture, Spring             2.86

  139      Mix Pasture, Summer             2.42

  140      Range, June Diet                2.35

  141      Range, July Diet                2.25

  142      Range, August Diet              2.15

  143      Range, September Diet           2.07

  144      Range, Winter                   1.83

  145      Meadow, Spring                  1.62

  146      Meadow, Fall                    1.88

  147      Meadow, Hay                     2.17

  148      Prairie, Hay                    1.74

  201      Alfalfa Hay, Early Vegetative-S 2.39

  202      Alfalfa Hay, Early Vegetative-N 2.42

  203      Alfalfa Hay, Late Vegetative-S  2.28

  204      Alfalfa Hay, Late Vegetative-N  2.31

  205      Alfalfa Hay, Early Bloom-S      2.17

  206      Alfalfa Hay, Early Bloom-N      2.24

  207      Alfalfa Hay, Mid Bloom-S        2.10

  208      Alfalfa Hay, Mid Bloom-N        2.17

  209      Alfalfa Hay, Full Bloom-S       1.99

  210      Alfalfa Hay, Full Bloom-N       2.02

  211      Alfalfa Hay, Late Bloom-S       1.88

  212      Alfalfa Hay, Late Bloom-N       1.92

  213      Alfalfa Hay, Mature-S           1.81

  214      Alfalfa Hay, Seeded             1.63

  215      Alfalfa Hay, Weathered          1.74

  216      Alfalfa Hay, dehydrated 15%CP   2.13

  217      Alfalfa Silage, Early Bloom     2.28

  218      Alfalfa Silage, Mid Bloom       2.10

  219      Alfalfa Silage, Full Bloom      1.99

  220      Birdsfoot, Trefoil, Hay         2.13

  221      Clover, Ladino Hay              2.17

  222      Clover, Red Hay                 1.99

  223      Vetch Hay                       2.06

  224      Leg Pasture, Spring             2.86

  225      Leg Pasture, Summer             2.39

  301      Barley, Silage                  2.17

  302      Barley, Straw                   1.45

  303      Corn Cobs, Ground               1.81

  304      Corn Silage, 25% Grain-N        2.46

  305      Corn Silage, 25% Grain-S        2.21

  306      Corn Silage, 35% Grain          2.49

  307      Corn Silage, 40% Grain          2.39

  308      Corn Silage, 40% GR + NPN       2.42

  309      Corn Silage, 40% GR + NPN + ca  2.46

  310      Corn Silage, 45% Grain          2.60

  311      Corn Silage, 45% GR + NPN       2.84

  312      Corn Silage, 45% GR + NPN + ca  2.71

  313      Corn Silage, 50% Grain          2.71

  314      CS50% + NPN + CA                2.98

  315      Corn Silave, Immature (no Ears) 2.35

  316      Corn Silage, Stalkage           1.99

  317      Corn Stalks, Grazing            2.38

  318      Oat, Silage Dough               2.13

  319      Oat, Straw                      1.63

  320      Oat, Hay                        1.92

  321      Sorghum, Silage                 2.17

  322      Wheat, Silage dough             2.06

  323      Wheat, Straw                    1.48

  401      Barley Malt, Sprouts w/hulls    2.57

  402      Barley Grain, Heavy             3.04

  403      Barley Grain, Light             2.78

  404      Corn, Hominy                    3.29

  405      Corn Grain, Cracked             3.25

  406      Corn Dry, Ear 45 lb/bu          2.78

  407      Corn Dry, Ear 56 lb/bu          2.96

  408      Corn Dry, Grain 45 lb/bu        3.18

  409      Corn Ground, Grain 56 lb/bu     3.18

  410      Corn Dry, Grain 56 lb/bu        3.18

  411      Corn Grain, Flaked              3.36

  412      Corn HM, ear 56 lb/bu           3.07

  413      Corn HM, Grain 45 lb/bu         3.25

  414      Corn HM, Grain 56 lb/bu         3.36

  415      Cottonseed, Black Whole         3.43

  416      Cottonseed, High Lint           3.25

  417      Cottonseed, Meal - mech         2.82

  418      Cottonseed, Meal - Sol-41%CP    2.71

  419      Cottonseed, Meal - Sol-43%CP    2.71

  420      Molasses, Beet                  2.71

  421      Molasses, Cane                  2.60

  422      Oats, 32 lb/bu                  2.64

  423      Oats, 38 lb/bu                  2.78

  424      Rice, Bran                      2.53

  425      Rice Grain, Ground              2.86

  426      Rice Grain, Polished            3.22

  427      Rye Grain                       3.04

  428      Sorghum, Dry grain              2.75

  429      Sorghum, Rolled grain           2.96

  430      Sorghum, Steam flaked           3.18

  431      Tapioca                         3.04

  432      Wheat, Ground                   3.18

  433      Wheat Middlings                 3.00

  434      Wheat Grain, Hard red spring    3.04

  435      Wheat Grain, Soft white         3.07

  501      Brewers Grain, 21% Dry Matter   2.53

  502      Brewers Grain, Dehydrated       2.39

  503      Canola, Meal                    2.49

  504      Coconut, Meal                   2.31

  505      Corn Gluten, Feed               2.89

  506      Corn Gluten, Meal               3.04

  507      Corn Gluten, Meal 60% CP        3.22

  508      Distillers Gr., + solubles      3.18

  509      Distillers Gr., Dehy - Light    3.18

  510      Distillers Gr., Dehy - Inter.   3.18

  511      Distillers Gr., Dehy - Dark     3.18

  512      Distillers Gr., Dehy - V. Dark  3.18

  513      Distillers Gr., solubles dehy   3.18

  514      Distillers Gr., Wet             3.25

  515      Lupins                          2.82

  516      Peanut, Meal                    2.78

  517      Soybean, Meal - 44              3.04

  518      Soybean, Meal - 49              3.15

  519      Soybean, Whole                  3.40

  520      Soybean, Whole Roasted          3.40

  521      Sunflower, Seed meal            2.35

  601      Apple, Pomace                   2.49

  602      Bakery, Waste                   3.22

  603      Beet Pulp, + Steffen\'s filt    2.39

  604      Beet Pulp, Dehydrated           2.68

  605      Citrus Pulp, Dehydrated         2.96

  606      Grape, Pomace                   1.19

  607      Soybean, Hulls                  2.89

  608      Linseed, Meals                  2.82

  609      Cottonseed, Hulls               1.63

  610      Wheat, bran                     2.53

  701      Bloodmeal                       2.39

  702      Feather, Meal                   2.46

  703      Fishmeal                        2.64

  704      Meat, meal                      2.57

  705      Tallow                          6.40

  706      Whey, Acid                      2.82

  707      Whey, Delact.                   2.57
  ------------------------------------------------------------------------

Source: National Research Council. 1996. Nutrient Requirements for Beef
Cattle, Seventh Revised Edition. Subcommittee on Beef Cattle Nutrition,
Committee on Animal Nutrition, Board on Agriculture. National Academy
Press. Washington, D.C.

**Chapter 1, Part H. Agriculture**

**References**

Allmaras, R.R., H.H. Schomberg, C.L. Douglas, and T.H. Dao (2000) Soil
organic carbon sequestration potential of adopting conservation tillage
in U.S. croplands. Journal of Soil and Water Conservation, 55, 365-373.

Australian Greenhouse Office 2000, National Carbon Accounting System
Technical Report No. 14, "Sampling, Measurement and Analytical Protocols
for Carbon Estimation in Soil, Litter and Coarse Woody Debris."

EPA (2003) Inventory of U.S. Greenhouse Gas Emissions and Sinks -
1990-2001. April 2003, available at:
http://Yosemite.epa.gov/oar/globalwarming.nsf/content/resourcecenterpublications.html.

EPA (2004) Inventory of U.S. Greenhouse Gas Emissions and Sinks -
1990-2002. April 2004, available at:
http://Yosemite.epa.gov/oar/globalwarming.nsf/content/resourcecenterpublications.html.

EPA date unknown. U.S. Environmental Protection Agency, AgStar Biogas
Handbook, Washington, DC, available at:
http://www.epa.gov/agstar/resources/handbook.html.

Follett R.F. (2001) Soil management concepts and carbon sequestration in
cropland soils. Soil and Tillage Research, 61:77-92.

Haas H.J., C.E. Evans, and E.F. Miles (1957) Nitrogen and Carbon Changes
in Great Plains Soils as Influenced by Cropping and Soil Treatments,
Technical Bulletin No. 1164 U.S. Department of Agriculture, State
Agricultural Experiment Stations, 111 pp.

IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National
Greenhouse Gas Inventories. Paris: Intergovernmental Panel on Climate
Change, United Nations Environmental Programme, Organization for
Economic Co-Operation and Development, International Energy Agency.

IPCC (2000) Good Practice Guidance and Uncertainty Management in
National Greenhouse Gas Inventories. Chapter 4: IPCC National Greenhouse
Gas Inventories Programme Technical Support Unit, Kanagawa, Japan. Data
also available at \<http://www.ipcc-nggip.ig

Johnson, K.A. and D.E. Johnson. 1995. Methane emissions from cattle.
Journal of Animal Science 73:2483-2492

Johnson, K. 2004. A SF~6~ Tracer Technique: Methane Measurements from
Ruminants. unpublished manual.

Kimble, J.M., R.B. Grossman, and S.E. Samson-Liebig, "Methodology for
Sampling and Preparation for Soil Carbon Determinations," in R. Lal,
J.M. Kimble, R.F. Follett, and B.A. Stewart, Assessment Methods for Soil
Carbon, pp. 15-30. Boca Raton, FL: CRC Press.

Lal R., J.M. Kimble, R.F. Follett, and C.V. Cole (1998) The Potential of
U.S. Cropland to Sequester Carbon and Mitigate the Greenhouse Effect.
Sleeping Bear Press, Chelsea, MI, 128 pp.

Lal, R., J.M. Kimble, R.F. Follett, B.A. Stewart, 2001. Assessment
Methods for Soil Carbon. Ch. 2, "Methodology for Sampling and
Preparation for Soil Carbon Determination," pp. 15-30; Ch. 6, "Spatial
Variability: Enhancing the Mean Estimate of Organic and Inorganic Carbon
in a Sampling Unit," pp. 69-86; Ch. 9, "Characterization of Soil Organic
Carbon Pools," pp. 117-129; and Ch. 10, "Measuring and Comparing Soil
Carbon Storage," pp. 131-146. Boca Raton, FL: CRC Press.

Paustian, K., O. Andren, H.H. Janzen, R. Lal, P. Smith, G. Tian, H.
Tiessen, M. Van Noordwijk, and P.L. Woomer (1997a) Agricultural soils as
a sink to mitigate CO2 emissions. Soil Use and Management, 13:230-244.

Paustian, K., H.P. Collins, and E.A. Paul (1997b) "Management Controls
on Soil Carbon," in: Paul, E.A., K. Paustian, E.T. Elliott, and C.V.
Cole (eds.), Soil Organic Matter in Temperate Agroecosystems: Long-Term
Experiments in North America. CRC Press, Boca Raton, FL, pp. 15-49.

Schlesinger, W. H. (1986) "Changes in Soil Carbon Storage and Associated
Properties with Disturbance and Recovery," pp. 194-220, in: J. R.
Trabalka and D. E. Reichle (eds.), The Changing Carbon Cycle: A Global
Analysis. Springer-Verlag, New York.

Smith, G.R. 2001. "Toward an Efficient Method for Measuring Soil Organic
Carbon Stocks in Forests," in R. Lal, J.M. Kimble, R.F. Follett, B.A.
Stewart, Assessment Methods for Soil Carbon, pp. 293-310. Boca Raton,
FL: CRC Press.

SSSA 2001. Soil Science Society of America, Internet Glossary of Soil
Science Terms. <http://www.soils.org/sssagloss/>

SSSA 1986. Soil Science Society of America, Book Series Number 5:
Methods of Soil Analysis: Part 1-4, 1986-2002.

USDA 1996a. U.S. Department of Agriculture, Agricultural Waste
Management Field Handbook.

USDA NRCS 1996b. U.S. Department of Agriculture, Natural Resources
Conservation Service National Soil Survey Center, Soil Survey
Investigations Report Number 42, Version 3.0 (1996), web site
<ftp://ftp-fc.sc.egov.usda.gov/NSSC/Lab_Methods_Manual/ssir42.pdf>.

USDA NRCS, 1997. National soil survey laboratory characterization data,
digital data, Natural Resources Conservation Service, U.S. Department of
Agriculture, Lincoln, NE.

**Technical Guidelines for Voluntary Reporting of Greenhouse Gases
Program**

**Chapter 1, Emission Inventories**

### Part I: Forestry Emissions

Outline

1.  Overview

1.1 Carbon Sequestration by the Forestry Sector

2\. Estimation Methods

> 2.1. Carbon Pools

2.2. Greenhouse Gases

2.3. Reporting Units

2.4. Units of Measure

2.5. Approaches to Calculations

> 2.5.1. The Basic Carbon Stock Calculation
>
> 2.5.2. Stock-change Approach
>
> 2.5.3. Flow Approach
>
> 2.5.4. Approaches for Wood Products
>
> 2.5.5. Approach for Biomass Energy
>
> 2.5.6. Partitioning the Land Base for Calculations

2.6. Basic Estimation Methods

> 2.6.1. Look-up Tables
>
> 2.6.2. Models
>
> 2.6.3. Direct Measurement
>
> 2.6.4. Rating System for Estimation Methods

3\. Sector-specific Issues for Forestry

3.1. Exclusions

3.2. Land-use Change

3.3. Permanence

3.4. Natural Disturbances

3.5. Sustainably Managed Forests

3.6. Incidental Lands

4\. Forestry Activities

4.1. Afforestation, Mine Land Reclamation, and Forest Restoration

4.2. Agroforestry

4.3. Forest Management

4.4. Short-rotation Biomass Energy Plantations

4.5. Wood Products

4.6. Urban Forestry

**Technical Guidelines Chapter 1, Part I: Forestry Emissions**

#### 1.I.1 Overview

This Part supports and supplements the General Guidelines for reporting
greenhouse gas information under Section 1605(b) of the Energy Policy
Act of 1992 (EPAct), and provides additional detail for the
forestry-sector component of Volume III, Section E.4, "Registering
Reductions from Carbon Storage." The General Guidelines provide the
rationale for the Voluntary Reporting of Greenhouse Gases Program and
overall concepts and methods to be used in reporting. Before proceeding
to the more specific discussion contained in this section of the
Technical Guidelines, reporters should become familiar with the General
Guidelines. This section relates the General Guidelines to the issues,
methods, and data specific to creating an inventory for emissions and
emission reductions associated with the forestry sector.

Appendices to this document provide detailed technical guidance for
conducting inventories and estimating changes in carbon storage using
different methods. Other sections of the Technical Guidelines address
the sectors of electricity, residential and commercial buildings,
industry, transportation, and agriculture.

The General Guidelines and supporting documents describe the rationale
and processes for estimating emissions and analyzing emissions-reducing
and carbon-sequestration activities. Certain procedures must be followed
to calculate, report, and register reductions associated with increases
in forest carbon stocks. This documentation is designed to provide the
background needed to complete the reporting forms.

The Department of Energy (DOE) with the support of the U.S. Department
of Agriculture, Forest Service (USDA Forest Service) and other agencies
of the U.S. Government have designed this Voluntary Reporting of
Greenhouse Gases Program to be flexible and easy to use. A variety of
methods for making estimates of greenhouse gas emissions and reductions
or sequestration are provided. The different methods range from simple
and inexpensive to complex and costly. Reporters may choose the simplest
available methods that provide estimates with a level of accuracy that
meets reporting objectives. For example, "default" factors and estimates
are provided for those wishing to enter data that are typical for
forestry activities in a region, but that may not be sufficiently
accurate for a specific entity to enable reductions to be registered.
For estimates that are more specific to an entity or activity,
measurement and modeling approaches are described for developing
estimates.

As a supplement to the General Guidelines, this Part is intended to
provide more specific guidance for developing an inventory of greenhouse
gas (GHG) emissions and carbon sequestration related to forestry, and
provide enough information and examples to enable reporters to make
estimates and fill-out the Program's reporting forms. The guidance
provided may need to be adapted to fit particular individual situations
due to the great variety of entities and activities participating in the
Program. The methods presented here have the scientific rigor necessary
to account for carbon stock changes for activities or entities of any
size, if they are used appropriately and supplemented if necessary by
additional information or measurements.

This Part focuses on estimating changes in quantities of stored carbon
as accurately as is practical considering the requirements for reporting
and registering reductions. Accuracy clearly depends on accounting for
all positive flows (emissions) of carbon from forests and negative flows
(sequestration) of carbon to forests and wood products. Information
presented in this section is consistent with protocols used to report
changes in forest carbon stocks in greenhouse gas inventories compiled
by the U.S. Environmental Protection Agency (EPA) and the U.S.
Department of Agriculture (USDA). This is achieved through the use of
consistent terminology, consistent definitions of ecosystem and wood
product carbon pools, and consistent estimation approaches based on
national forest inventory statistics.

##### 1.I.1.1 Carbon Sequestration by the Forestry Sector

Forests remove carbon from the atmosphere and store it in vegetative
tissue such as stems, roots, barks, and leaves. Certain forestry-sector
activities can maintain or enhance this carbon sequestration. Through
photosynthesis, all green vegetation removes carbon dioxide (CO~2~) and
releases Oxygen (O~2~) to the atmosphere. The remaining carbon is used
to create plant tissues and store energy. During respiration, carbon
containing compounds are broken down to produce energy, releasing carbon
dioxide in the process. Any remaining carbon is sequestered until the
natural decay of dead vegetative matter or combustion releases it as
carbon dioxide to the atmosphere. The net carbon stock in forests
increases when the amount of carbon withdrawal from the atmosphere
during photosynthesis exceeds the release of carbon to the atmosphere
during respiration.

Some of the carbon in forests is released to the atmosphere during the
harvesting of timber. However, whether or not the bulk of the carbon is
released, and when, depends on the fate of the harvested timber. If the
timber is used to make wood products, a portion of the sequestered
carbon will remain stored for up to several decades or longer. If the
harvested trees are burned and used to produce energy, carbon will be
released through combustion, offsetting carbon that would have been
released through the burning of fossil fuels. If the energy is not
recovered, there will be no associated offset, and only carbon dioxide
emissions from the burning of the wood. These cases demonstrate that
harvested wood can sequester carbon for different time periods, and even
potentially offset other emissions, depending upon its eventual use.

The forestry sector affects a broad range of potential greenhouse gas
emission sources, emission reduction activities, and carbon
sequestration activities. Examples include, but are not limited to, the
following:

-   Afforestation (the establishment of new forests on lands that have
    not been recently forested) can lead to large increases in carbon
    stocks on the treated area.

-   Restoration of native vegetation and wildlife habitat has the
    additional potential to sequester large quantities of carbon.

-   Reforestation (active regeneration of harvested forest land) can
    accelerate the natural regeneration process and provide for the
    establishment of fast-growing species.

-   Agroforestry (the cultivation of trees with crops or pasture) can
    sequester carbon and potentially decrease the requirements for
    fossil fuel energy as well as energy-intensive chemicals in the
    production of food and fuel.

-   Typical forest management practices may be modified to increase the
    rate of carbon sequestration or reduce emissions from the decay of
    specific forest carbon pools.

-   Short-rotation woody biomass plantations can sequester carbon and
    provide energy feedstocks that displace fossil fuels in energy
    production.

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-   Protecting existing forests from harvest and/or from conversion to
    non-forest land use may prevent the release of carbon stocks.

-   Low-impact harvesting methods can decrease emissions from soil
    disturbance and biomass decay that often follow timber harvest.

-   Management of the carbon flows in the processing of harvested timber
    for wood products can reduce emissions from wood waste and energy
    used.

-   Planting trees in urban areas (urban forestry) increases carbon
    sequestration and can reduce the energy used in heating or cooling
    homes and businesses.

The emission reductions and carbon sequestration activities in the
forestry sector range from those that may be simple and relatively easy
to evaluate (such as afforestation) to those with more complex effects
(such as agroforestry and land restoration). The cost and feasibility of
evaluating the emission reductions and sequestration are important
factors to consider when selecting methods and deciding on how to report
at the activity or entity level.

Accurately measuring the effects of forestry activities for entity or
activity reporting can prove especially challenging. Nearly every action
undertaken in the management of forests causes changes in biomass
stocks, and therefore in net carbon flows. For example, tree planting
establishes a new carbon sink; thinning forests shifts biomass increment
to fewer trees; and harvesting removes stored carbon from the forest
(but does not necessarily release all of it back into the atmosphere).
Even the elimination of an activity, such as stopping the clearing of
forests for agricultural use, can influence carbon flows by allowing
forest regrowth and other natural processes to proceed uninterrupted.

Two important issues must be considered when measuring and estimating
the effects of forestry activities on carbon flows for activity and
entity reporting. The first is that forestry practices typically trigger
ecosystem responses that change over time. For example, a newly
established forest will take up carbon at a low rate initially, and then
pass into a period of relatively rapid carbon accumulation. The carbon
uptake rate will then typically decline as growth is balanced against
mortality in the older forest. From this point in time, standing live
tree biomass may not increase, but evidence suggests that carbon may
continue to flow into other forest carbon pools until the forest is
removed by harvest or a natural disturbance event. Advanced measures of
carbon flows must account for these dynamic effects.

The second issue is that the net effects of activities on carbon flows
in forest ecosystems include many pools of carbon. Carbon accounting
should be comprehensive, addressing the net effects of activities on all
carbon flows. There are several carbon pools (such as aboveground
biomass, belowground biomass, litter, soil, etc.) in forests. Forestry
activities cause carbon to move between the various pools and to/from
the atmosphere. . For example, forest management may be very effective
at increasing the accumulation of biomass in commercially valuable
forms---that is, in the trunks of commercial tree species. This
increased growth may simply result from reducing competition from other
types of trees, causing a transfer of carbon uptake from one group of
trees to another. Forestry activities can also have effects on forest
soils, woody debris, and the amount of carbon in wood products. The net
carbon flow effects of any activity will be the sum of all the
individual effects on the different carbon pools.

#### 1.I.2 Estimation Methods

##### 1.I.2.1 Carbon Pools

Forestry activities affect many different carbon pools. Table 1.I.1
highlights the key carbon pools that should be considered for measuring
net carbon flows, using default estimates or models, and reporting.
Definitions of many of the terms are included in the glossary. With the
exception of harvested wood, estimates are directly associated with land
area.

###### Table 1.I.1 Relationships among Carbon Pools of Forest Ecosystems and Wood Products for Different Parts of Accounting Rules and Guidelines

  -------------------------- ---------------------- ----------------------
  **Basic carbon pools for   **Aggregated carbon    **Aggregated carbon
  detailed measurement and   pools used in default  pools for reporting**
  estimation**               tables**               

  Live trees: above-ground   Live trees             Ecosystem carbon

  Live trees: below-ground                          

  Tree seedlings             Understory vegetation  

  Shrubs, herbs, forbs,                             
  grasses                                           

  Standing dead trees:       Standing dead trees    
  above-ground                                      

  Standing dead trees:                              
  below-ground                                      

  Down dead wood             Down dead wood         

  Stumps and dead roots                             

  Fine woody debris          Forest floor           

  Litter                                            

  Humus                                             

  Soil carbon                Soil carbon            

  Harvested wood mass (total Harvested wood mass    Wood products carbon
  removed)                   (in use and in         
                             landfills)             

                             Harvested wood mass    Not counted in
                             (burned for energy)    emissions inventories
                                                    because it is biogenic

                             Harvested wood mass    Not directly reported,
                             (emissions/not used    but counted as a
                             for energy)            reduction in other
                                                    forest carbon pools
  -------------------------- ---------------------- ----------------------

##### 1.I.2.2 Greenhouse Gases

Forestry activities mainly affect the exchange of carbon dioxide between
the land and the atmosphere, thus accounting for carbon stocks and flows
is the primary focus of these accounting rules and guidelines. There may
be cases where other greenhouse gases are significantly affected by an
activity, and the General Guidelines specify that emissions greater than
3 percent of total emissions (in carbon-equivalent units) should be
quantified. Of particular concern are nitrous oxide, which may be
released from fertilized forests, and methane, which may be released
from forested wetlands. Reporters should consider whether those gases
are affected by their activities and estimate the net flows if
significant. Note that no guidelines are provided in this section for
monitoring, estimating, or reporting non-CO~2~ gases for forestry.
Reporters should consult the Technical Guidelines for other sectors if
reporting non-CO~2~ greenhouse gases is necessary.

##### 1.I.2.3 Reporting Units

All final measures of net emissions and net emission reductions should
be expressed in the form of carbon dioxide equivalent in metric units.
For carbon, carbon dioxide equivalent is the weight of the gas, which is
higher than the weight of the carbon alone because the gas also includes
oxygen atoms. A simple multiplication factor, 3.67, can be used to
convert carbon to carbon dioxide equivalent.

##### 1.I.2.4 Units of Measurement

Both English and metric units of measurement are used in this section
and associated appendices, and reporting will be allowed in both. Table
1.I.2 provides the most common conversion factors needed to change units
of measurement from one system to the other. The following abbreviations
are relevant to the conversion factors, and are used throughout the
remainder of this section:

A = area

ac = acre

C = carbon

ha = hectare

I = inventory of carbon stock

MT/ha = metric tons per hectare

t/ac = short tons per acre

###### Table 1.I.2 Conversion Factors for Units of Measurement

  ----------------------- ----------------------- -----------------------
  **Measurement:**        **English Unit:**       **Metric Unit:**

  Area                    1 acre                  0.4047 hectares

  Area                    2.47 acres              1 hectare

  Mass                    1 Short ton             0.9072 metric tons

  Carbon                  1 short ton per acre    2.241 metric tons per
                                                  hectare

  Carbon                  892 pounds per acre     1 metric ton per
                                                  hectare
  ----------------------- ----------------------- -----------------------

##### 1.I.2.5 Approaches to Calculations

**1.I.2.5.1 The Basic Carbon Stock Calculation**

Calculating the quantity of carbon in an area of forest requires two
pieces of information: the area of forest land included in the entity or
activity, and the amount of carbon per unit of area. The following
formula illustrates the basic calculation:

**I = A x C/ha**

> **Where:**

**I = inventory of carbon stock**

**A = area in hectares**

**C/ha = quantity of carbon stored per hectare (in metric tons per
hectare).**

The variable C/ha must include estimates of all the relevant carbon
pools. An estimate of harvested wood products for the activity or entity
may also be required, but it may not be necessary to estimate that
quantity on a per-hectare basis.

**1.I.2.5.2 Stock-Change Approach**

Carbon flows from forests and forestry operations are typically
estimated using changes in an inventory of carbon stocks. The general
formula for calculating changes in carbon stocks is:

**Net annual carbon stock change in year t = (I~t~ - I~t-1~)**

> **Where:**

**I~t~ = inventory of carbon stock (in mass units such as short tons
or**

**metric tons) in the forest area in year t**

**I~t-1~ = inventory of carbon stock (in mass units such as short tons
or**

> **metric tons) in the forest area in the year immediately preceding
> t**

Since forest carbon stocks may change slowly relative to the size of the
carbon stock, annual measurements or estimations of the inventory of
carbon stock are unlikely to capture significant changes. It is
therefore recommended that successive inventories be conducted over
periods of 5 years. Net carbon flows should be estimated as the average
annual difference in carbon stocks between inventory years. For example,
to estimate net average carbon stock change for a 5-year period, the
estimate can be derived as:

**Net average annual carbon stock change = (It -- It-5)/5**

> **Where:**
>
> **I~t-5~ = inventory of carbon stock in the forest area 5 years before
> the**
>
> **current year**
>
> **I~t~ = inventory of carbon stock in the forest area in the current
> year**

Reporting entities must establish an inventory for the base period to
begin the estimation and reporting process, using an estimation method
described in Section 1.I.2.6. The inventory must be updated each year
for annual reporting. Updates may be provided using a combination of
different estimation methods. For example, an entity may prepare an
inventory for the initial year within the base period using the direct
measurement approach, but not perform a second such measurement five
years later. To submit reports for any reporting years between the
initial and the second inventory, entities will need to estimate changes
in carbon stocks relative to the initial year (within the base period)
using default tables or a model. These estimates can then be corrected
once the second measurement becomes available.

**1.I.2.5.3 Flow Approach**

For some carbon pools, such as carbon in soils, carbon stocks and
changes in carbon stocks cannot easily be estimated, so a flow approach
may be used to estimate changes in carbon stocks over a period of time.
For example, a reporter may directly estimate annual flows of carbon
using carbon dioxide flux monitoring methods or models of the impacts of
activities on carbon flows. Carbon dioxide flux monitoring methods
provide a direct estimate of the net exchange of carbon between the
ecosystem and the atmosphere over short periods of time. Similarly, some
ecosystem models simulate carbon flows at daily, monthly, or annual time
periods based on data about the forest ecosystem and its physical
characteristics, estimates of how processes such as photosynthesis
affect carbon flows, and information about the effects of forest
practices. Short-term estimates from monitoring or models can be
extrapolated to estimate the net change in carbon stocks over a year.

If models or flux monitoring are used for annual estimates instead of
successive inventories or direct measurement, it is recommended that
inventories of carbon stocks be conducted periodically to verify that
the activity or entity is actually behaving as the model or short-term
flux monitoring predicts. If a discrepancy is detected, estimates should
be adjusted to bring the reported flows back in line with measured
carbon stocks.

**1.I.2.5.4** **Approaches for Wood Products**

Additional accounting is required for carbon in wood that is removed
from the forest. When timber is removed from the forest, the portion of
its carbon that is released to the atmosphere depends upon how the
timber is used. To illustrate, the burning timber releases the stored
carbon immediately, whereas the carbon stored in lumber or furniture may
not be emitted for decades. If carbon remaining in wood products is not
part of the accounting system, the calculation of change in carbon
stocks for harvested forests overestimates emissions because the carbon
in the harvested wood is assumed to be immediately released to the
atmosphere. Carbon pools in wood products include wood-in-use (e.g.,
lumber, furniture, and paper) and wood products that have been discarded
in landfills or recycled.

There are two basic approaches that can be used to estimate the quantity
of carbon in wood products. The first approach is to track, over time,
the decay of materials stored in wood products and account for the
emissions in the year in which they occur. If this approach is used,
each individual harvest year must be followed by separate annual
tracking and reporting of the changes in wood product pools. The second
approach is to estimate the quantity of carbon remaining in harvested
wood products at 100 years after harvest, and report that quantity in
the year of harvest. Regardless of which approach is used, accounting
for carbon in wood products begins at the first harvest that occurs
after the start year selected by the reporter. It is not necessary to
estimate changes in the carbon content of wood products that were
harvested in previous years. A technical Appendix to this document
includes tables, decay-rate equations and default coefficients that can
be applied to inventory estimates, harvest volumes or wood product
statistics to estimate carbon stored in wood products at any time after
harvest using one of the two basic approaches.

**1.I.2.5.5 Approach for Biomass Energy**

Biomass energy involves an important cross-sectoral linkage between
forestry and the electricity supply sector. Analysis of the carbon flows
should account for both changes in carbon sequestration (using the
methods described in Section 1.I.2.6) and the effects of substituting
biomass energy for fossil-fuel energy. Calculating the release of carbon
from the combustion of biomass fuel and the dis­placement of emissions
from fossil fuels is described in the Technical Guidelines for the
electricity supply sector.

**1.I.2.5.6 Partitioning the Land Base for Calculations**

Reporters may have a diverse land base that is affected by different
forestry activities, managed at different intensities, or that has a
variety of existing data. One of the first steps in preparing
entity-wide or sub-entity estimates of carbon fluxes from forests is to
organize the underlying data on land conditions into manageable units,
referred to here as forest strata. Land should be grouped into forest
strata using a logical framework that aggregates similar land units. For
example, land could be partitioned by average tree age, forest type,
productivity class, and management intensity. In many cases forest
strata will be contiguous, although this is not a necessary condition.

In addition to currently having similar characteristics, reporters
should expect that land in a given forest strata will be managed
similarly in the future. It may be necessary to aggregate or
disaggregate land in a particular forest strata in future reports
depending on changes in management practices. A small entity may have
only one or two forest strata, while larger entities could have land in
virtually every age strata for numerous types of forest.

Partitioning allows the use of more than one estimation method, giving
the reporting entity some flexibility to reduce overall estimation costs
by matching methods to the level of accuracy needed. Use of partitioning
does not require defining separate sub-entities because it is part of a
single calculation method.

##### 1.I.2.6 Basic Estimation Methods

**1.I.2.6.1 Look-up Tables**

The simplest approach to estimating carbon stock inventories is to use
look-up tables that represent average forest conditions for a region,
ownership class, forest type, and productivity class. Before using the
look-up tables, it is necessary to determine the area of land to be
included in the estimate, and characterize that area (i.e., stratify the
land area) in a way that is compatible with the estimates in the look-up
tables. The average values presented in the look-up tables can then be
multiplied by the area estimate to obtain the carbon stock estimate.
Although this approach is simple and inexpensive to use, the uncertainty
for individual activities or entities may be high relative to other
approaches that may be more applicable to the specific circumstances of
the activity or entity.

A variety of look-up tables, based on inventories conducted across all
U.S. forestlands, is provided in the Appendix to this section. Since
these tables represent average conditions over large areas, the actual
carbon flows for a specific activity or entity may be different than the
estimate developed by using the default carbon factors in the look-up
tables. If it is determined that the conditions for an activity or
entity are not represented by any of the pre-compiled look-up tables,
reporters may choose to generate custom look-up tables or use a
different estimation method (models or direct measurement). Entities
generating custom tables must follow the guidance on new methods in Part
1, Section 1.A.4.

Data provided in the look-up tables will generally not be appropriate
for use by entities reporting on forests outside of the United States
unless the conditions of the forest are consistent with climate regions
and forest types covered by the tables. In most cases, entities
reporting on non-U.S. forest operations should use models or direct
measurement to estimate carbon stock changes following the guidance
provided in the following sections.

**1.I.2.6.2 Models**

A variety of models are available for many different forest conditions
and activities. In some cases, models may be more accurate than look-up
tables for specific activities or entities, but may require more effort
and possibly higher cost. Models useful for estimating quantities of
forest carbon may be based on traditional empirical timber production
models modified to predict carbon stocks or flows. More recently, models
that include the representation of key ecosystem processes such as
photosynthesis and respiration are becoming available. Such models may
be applied to conditions and treatments beyond those represented in the
data used to develop the models, but this should be done cautiously and
with appropriate verification to ensure the accuracy of estimates.

Before using a model it is necessary to determine the area of land to be
included in the estimate, and characterize that area in a way that is
compatible with estimates from the model. To achieve the best results,
the selected model should be parameterized for the specific conditions
of the land area to which the model is applied. Partitioning of the land
area into relatively uniform strata may help in matching and
parameterizing a model for a specific application.

In general, models may be useful tools for estimating both entity-wide
carbon flows and activity-level accomplishments. If a modeling approach
is used, periodic validation of model estimates of carbon stocks with
field data is strongly recommended. Models may also be used to update
inventories of carbon stocks for annual reporting in the years in
between direct measurements made at multi-year intervals.

Models should be evaluated (validated) to be sure they are appropriate
for each application. Specific guidance for using and evaluating models
is provided in the Appendix. The basic elements of model evaluation are:
(1) scientific peer review, (2) quantitative comparison of model results
to field observations, and (3) sensitivity analyses.

A user-friendly model developed by the United States Department of
Agriculture Forest Service (USFS) called Carbon Online Estimation (COLE)
is available via a web interface at <http://ncasi.uml.edu/COLE/>. COLE
provides customized estimates of forest carbon for user-selected areas
of the conterminous United States. The model allows users to designate
an area of interest, and currently provides area, growing-stock volume,
and carbon pool estimates for the conterminous United States.
Designating areas that are similar to the area being reported on will
ensure that the carbon pool estimates obtained will be more accurate
than values obtained from the look-up tables provided in the Appendix.

Entities using models other than the COLE model must follow the guidance
on new methods in Chapter 1, Part A, Section A.4 of the Technical
Guidelines.

**1.I.2.6.3 Direct Measurement**

The most accurate way to estimate carbon stocks or flows for an activity
or entity is to use direct measurement, which involves developing and
implementing a sampling and estimation approach that is appropriate and
efficient for the land area being measured. Implementing the direct
measurement approach involves the following steps:

-   delineate the area (by strata) to be sampled

-   determine the number of sample locations required

-   design an efficient sample plot layout

-   decide exactly which variables to measure

-   collect and compile the data

-   convert the raw data into estimates

-   perform quality assurance and quality control over the monitoring
    operation

The effort required to perform direct measurement, and thus the cost, is
usually higher than using look-up tables or models, although the
uncertainty of the resulting estimates should be considerably lower. In
many situations, reporters may wish to consult a specialist in forest
inventory and monitoring to assist in applying the direct measurement
approach. Detailed guidance for using a measurement approach is provided
in the Appendix.

**1.I.2.6.4 Rating System for Estimates**

Part A of this Chapter, "Introduction," describes a rating system for
estimation methods. The rating system for forestry sector approaches
follows the logic in Table 1.I.3, as long as the technical guidelines in
this section are closely followed.

###### Table 1.I.3 Forestry Sector Rating System

+-------------------------------------+----------------------+---------+
| **Forest Ecosystem Carbon Pools**   | **Harvested Wood     | **R     |
|                                     | Products Pool**      | ating** |
+-------------------------------------+----------------------+---------+
| > Estimates from look-up tables     | > Use of an          | > A     |
| > that match specific site          | > approved^1^ model  |         |
| > conditions and management         | > validated with     |         |
| > practices, as documented using    | > data specific to   |         |
| > independent data or information.  | > the product mix of |         |
| >                                   | > the entity         |         |
| > Use of the USFS COLE model or an  |                      |         |
| > approved^1^ model, validated with |                      |         |
| > data specific to the site         |                      |         |
| > conditions and management         |                      |         |
| > practices.                        |                      |         |
| >                                   |                      |         |
| > Sampling with quantified accuracy |                      |         |
+-------------------------------------+----------------------+---------+
| > Estimates in look-up tables       | > Use of specific    | > B     |
| > adapted to specific site          | > data on harvest    |         |
| > conditions and management         | > and product mix    |         |
| > practices.                        | > and default decay  |         |
| >                                   | > factors provided   |         |
| > Use of an approved^1^ model that  | > in section 4 of    |         |
| > is parameterized specifically for | > the Appendix       |         |
| > site conditions and management    |                      |         |
| > practices.                        |                      |         |
| >                                   |                      |         |
| > Use of the Forest Service COLE    |                      |         |
| > model                             |                      |         |
+-------------------------------------+----------------------+---------+
| > Typical application of regional   | > Use of aggregate   | > C     |
| > look-up tables that generally     | > data on harvest    |         |
| > match the site conditions and     | > and default decay  |         |
| > management practices.             | > factors provided   |         |
| >                                   | > in section 4 of    |         |
| > Use of an approved^1^ model that  | > the Appendix       |         |
| > generally matches site conditions |                      |         |
| > and management practices.         |                      |         |
+-------------------------------------+----------------------+---------+
| > Use of look-up tables for site    |                      | > D     |
| > conditions and management         |                      |         |
| > practices that are not            |                      |         |
| > represented by the tables.        |                      |         |
+-------------------------------------+----------------------+---------+

^1^Reporters may obtain DOE approval for the use of methods that are not
provided in the guidelines. Information on approval of new methods is
provided in Chapter 1, Part A, Section A.4 of the Technical Guidelines.
Reporters may also certify that in using a model, they have followed the
guidelines in the modeling Appendix to this document.

The accuracy of estimates from the look-up tables will depend on how
well the estimates in the tables represent the specific conditions of
the land area or strata for which an estimate is required. The more the
estimation method approximates the actual site conditions and management
practices, the greater the accuracy and, consequently, the accuracy
rating. Thus, while applying a regional estimate from a look-up table to
a specific tract of land would be rated "C," modifying the information
contained in look-up tables to match site-specific characteristics and
management conditions would be rated "B." Estimates derived from look-up
tables can be rated "A" if independent data and information are used to
document that the look up tables match site conditions and management
practices.

As described in subsection 1.I.2.6.2, the COLE model may be used to
generate estimates that are rated "B." The rating for other models will
depend on how well the model represents the specific conditions of the
land area. A model that is developed specifically for a reporter's land
conditions and management practices may achieve a higher rating,
especially if the model is validated. Similarly, use of an inappropriate
model for the land characteristics and practices may result in a lower
rating. Entities using models other than the COLE model must use the
guidance on new methods in Chapter 1, Part A, Section A.4 of the
Technical Guidelines, or may follow the guidelines in the modeling
Appendix to this section.

The direct measurement approach allows reporters to develop an estimate
of carbon stocks and flows with known, quantified accuracy. Such an
estimate would be rated "A."

#### 1.I.3 Sector-Specific Issues for Forestry

This subsection addresses a number of issues specific to activity and
entity-wide reporting in the forestry sector. The text provides general
guidance for reporters to use to develop estimates of the net effects of
forestry activities. It may not be necessary to account for all these
issues for a specific forestry activity undertaken by a specific entity,
but each issue should be considered by reporters before developing
estimates of net carbon flows.

##### 1.I.3.1 Exclusions

The General Guidelines allow reporters to exclude certain emissions that
are comparatively small as *de minimis*---those up to 3 percent of the
total emissions in carbon dioxide equivalent. The General Guidelines
also permit categorical exclusions of non-anthropogenic emissions.

These allowable exclusions should be considered when addressing issues
such as natural disturbance, which greenhouse gases to report and carbon
pools to measure, and which estimation approach to use for different
land areas.

##### 1.I.3.2 Land-Use Change

Land-use change is a change in land classification among these
categories: forest land, cropland, grassland, and developed land
(including urban land). Reporters should refer to the glossary for
definitions of these land classes. Some forestry activities are by
definition a change in land use (e.g., afforestation).

Land-use change may affect all or part of the land area of an entity or
activity. Since the estimation methods for land-use change may be
different than the estimation methods for other land, determining the
area where land-use change has occurred is important.

When estimating changes in carbon stocks from land-use change, reporters
must be careful to use methods that are compatible with both forest and
non-forest land uses. For example, soil carbon should be defined to a
consistent depth, so that when comparing the estimated stock of soil
carbon of two different land uses, any differences reflect the change in
the land use, and not the use of two different estimation methods.

To estimate the change in carbon stocks for afforestation, reporters may
use any of the methods described in Section 1.I.2.6. Section 1.I.4.1
describes afforestation activity and discusses some of the issues that
should be considered.

Deforestation is not included among the list of forestry activities
because it causes a reduction in forest carbon stocks. Nonetheless, an
entity should estimate the effects of deforestation on carbon stocks as
part of their comprehensive greenhouse gas inventory. Of the methods
described in Section 1.I.2.6, measurement and modeling can be
appropriately applied to estimate changes in carbon stocks from
deforestation. To use the look-up tables, additional assumptions are
required. The look-up tables provide estimates of pre-harvest carbon
stocks for each ecosystem component; however, the individual components
should be treated according to the following table of assumptions:

###### Table 1.I.4. Assumptions

  --------------------------------- -------------------------------------
  **Ecosystem** **Component**       **Deforestation** **Assumption**

  Trees                             100 percent loss

  Understory vegetation             100 percent loss

  Standing dead wood                100 percent loss

  Down dead wood                    100 percent loss

  Forest floor                      100 percent loss

  Soil                              10% loss each 5 years for 15 years
  --------------------------------- -------------------------------------

Wood products from deforestation should be counted and estimated using
the methods described in the harvested wood products Appendix.

When incidental lands are converted to developed uses, the methods for
deforestation described above should be followed using the forestry
look-up tables that most closely match climate conditions and tree
species composition of the land in question. After conversion, carbon
stocks on developed lands can be assumed to not change. If trees are
planted on developed lands, entities may follow the guidance on Urban
Forestry below to estimate carbon stock changes in urban trees.

##### 1.I.3.3 Permanence

Permanence refers to the longevity of a carbon pool and the stability of
its stocks. Carbon that is sequestered in soils, vegetation, or wood
products is not necessarily permanently removed from the atmosphere. A
different landowner or change in management objectives may change
forestry activities originally intended for one purpose. Landowners may
change their practices causing the release of stored carbon, or natural
disturbances (discussed in the next subsection) may cause the loss of
stored carbon to the atmosphere. This subsection addresses the issue of
the longevity of carbon pools and associated reporting considerations.

As a general rule, all changes in carbon stocks should be accounted for
by periodic inventory and reporting. Such changes in carbon stocks are a
response to the logical progression of events that affect an activity or
entity over time and should be monitored accordingly. Calculations
should include effects on all carbon pools, both positive and negative,
so that reporters can record the net effect on carbon flow. Thus, for
most cases, permanence is not an issue because the periodic inventory
and annual reports should reflect changes in net carbon flows, whether
positive or negative, when they occur.

The permissible exclusion of the effects of natural disturbances
represents a case where the reporter may choose to explicitly account
for a loss of carbon stocks, as discussed below.

##### 

##### 

##### 

##### 1.I.3.4 Natural Disturbances

Carbon in forests may be lost to natural causes such as an insect
epidemic, drought, or wildfire. Those events may happen at any time
during the duration of reporting and may affect all or only a portion of
the land area within activity or entity boundaries. Natural disturbances
may be rare events, in which case the effects on estimated carbon flows
may be small when averaged over large forested areas or long periods of
time.

The General Guidelines provide that natural disturbances may be excluded
from calculations to determine registered reductions, thus requiring
reporters to make a separate estimate of the effect of natural
disturbances on all carbon pools. If the effects of natural disturbances
can be separated from other causes of changes in carbon pools, the
estimated changes in carbon stocks resulting from natural disturbances
should not be deducted from the annual estimate for the entity.
Likewise, the entity should not claim increases in carbon stocks as a
result of the regrowth of forests after natural disturbance until the
carbon stocks return to pre-disturbance levels. To keep track of changes
after disturbance, the entity should identify disturbed land as a
separate stratum in the estimation process (see subsection 1.I.2.5.6 on
partitioning the land base).

Catastrophic disturbances such as wind storms may cause obvious and
easily estimated changes in carbon stocks, while in other cases, such as
a one-year period of insect defoliation, it may be difficult after a few
years to separate the effects of the natural disturbance from other
factors. In some cases, the inventory of base year/period carbon stocks
may take into account average levels of natural disturbance, provided
that the inventory for the base year/period is an accurate reflection of
typical conditions and that natural disturbances occur relatively
frequently. The estimated carbon stocks for both the reporting year and
base year/period will thus include an average or typical level of
natural disturbances, and there is no need to separately account for
them.

##### 1.I.3.5 Sustainably Managed Forests

Forest certification systems require landowners to harvest at
sustainable rates, thus preventing long-term declines in carbon stocks.
Carbon stocks in sustainably managed forests will fluctuate in response
to natural disturbances, harvest schedules, changes in markets, and
changes in technology. Nevertheless, it is valid to conclude that
significant long-term declines in forest carbon stocks are unlikely to
occur in sustainably managed forests when considering all forests carbon
pools such as soil, litter, biomass and long-lived products.

Entities may assume there is neither an increase nor decrease in carbon
stocks on certified sustainably managed forests. The entity can claim
that changes in sequestration for forests managed under certified
sustainable management systems are *de minimis*. Third-party
certification systems, such as the following, should be used to
determine that lands are sustainably managed:

1.  The Sustainable Forestry Initiative (SFI)

2.  Forest Stewardship Council

3.  The American Tree Farm System

4.  Green Tag Forestry, National Woodlands Owners Association

While there are some differences among the major certification programs
in their goals and technical details, all of the programs set high
standards and have rigorous third-party audit protocols.

All or part of an entities' forest land can be certified as being
managed sustainably. Entities may choose to include actual estimates of
changes in carbon stocks on some of their lands, rather than relying on
the assumption of *de minimis* changes.

If an entity chooses to use the assumption that sustainable forest lands
are *de minimis* on part of their lands and report actual changes in
carbon stocks on other lands, the entity should document that the
certification of sustainability applies to the lands being considered
*de minimis*, independent of the entities' other lands. Once an entity
classifies a portion or all of its lands as sustainably managed forest,
it may not report carbon sequestration on the lands categorized as
sustainably managed in future reports.

##### 1.I.3.6 Incidental Lands

Incidental lands are entity landholdings that are a minor component of
an entity's operations and are not actively managed for the production
of goods and services, including: transmission, pipeline, or
transportation right of ways that are not managed for timber production;
land surrounding commercial enterprises or facilities; and land where
carbon stock changes are fundamentally determined by natural factors.
Entities have the option to use the methods in these guidelines (e.g.,
look-up tables, models, or direct measurement) to estimate changes in
terrestrial carbon stocks on incidental lands or to report that carbon
stocks on incidental lands are not changing. Regardless of which option
is chosen, entities must report on the area and type of incidental lands
owned. If incidental lands are converted to developed uses, the impact
of the development on the carbon stocks must be accounted for in the
entity inventory following the guidance in Section 1.I.3.2 for land use
changes.

#### 1.I.4 Forestry Activities

This section describes the procedures for estimating changes in carbon
stocks for seven general classes of forestry activities. Small entities
can report and register activity-based carbon emissions and
sequestration. Some larger entities may find it useful to organize their
entity-wide inventories by forestry activities. Each activity class has
unique characteristics that should be considered in making estimates and
performing activity or entity analysis. The activities included are
broad but not comprehensive, and are described here to provide general
guidance on how to apply the estimation approaches contained in this
section.

##### 

##### 

##### 

##### 

##### 

##### 1.I.4.1 Afforestation, Mine Land Reclamation, and Forest Restoration 

Forests may be established to replace another land use such as cropland
or pastureland, may be used to reclaim abandoned mine lands, or may be
established as part of a land restoration activity.

***Afforestation*** is a change in land use that may greatly alter
carbon stocks on a site. Tree planting activities have the benefit of
producing large gains in carbon stocks (at least in the initial decades
of tree growth) because they usually replace land uses that have a
relatively constant stock of carbon from year to year.

Planting trees on nonforested land has been widely promoted as an
effective tool for increasing carbon sinks globally; thus tree planting
has received the most attention in the analysis of forestry's effects on
global carbon cycles. There are numerous sources of information on the
carbon sequestered and stored by forests after afforestation, and
reference examples can be found in the studies cited in the Appendix.
Published studies indicate it is critical to distinguish among species
types, the productivity class of the forest site, and the intensity of
management efforts.

***Mine land reclamation*** is a special case of afforestation. For many
areas of abandoned or unreclaimed mined land, some vegetation may be
established but it often accumulates carbon at a very slow rate due to
slow plant growth on the highly disturbed and compacted soils. Mine land
soils are depleted of carbon, therefore the potential to increase carbon
in those soils may be much higher than for any other forestry activity.
Reporters should be particularly attentive to estimating the changes in
soil carbon on reclaimed mine land.

***Forest restoration*** can often be considered a special case of
afforestation with regards to estimating changes in carbon stocks. The
goal of the restoration activity is to return the land to its original
structure and species composition. If the land is in nonforest use prior
to initiation of the restoration activity, the activity meets the
definition of afforestation. If the land is in forest use prior to the
initiation of the restoration activity, the activity meets the
definition of forest management and reporters should refer to Section
1.I.4.3.

The major effect of afforestation is to increase carbon stocks by the
growing trees and the developing forest ecosystem. Other factors to
consider include biological and energy-related emissions during the
planting process, and emissions resulting from the use of fertilizers.

The rate of increase in carbon stocks depends upon several factors,
including tree species, geographic area, soil type, precipitation,
slope, and aspect. The annual change in carbon stocks must be determined
for each reporting year, and can be accomplished on the basis of
periodic field measurements, computer models, or look-up tables provided
in this document.

##### 

##### 

##### 

##### 

##### 1.I.4.2 Agroforestry

##### 

Agroforestry combines agriculture (crops and/or animals) and
silviculture on the same tract of land. Because it emphasizes the use of
woody and perennial crops and biological fertilizers, it may provide
agricultural products with less intensive energy input and sequester
more carbon than traditional agriculture. Agroforestry systems can be
quite complex, addressing not only production of grains and fruits for
human consumption, but also the production of feed and forage for
livestock, the production of wood fuel, fiber and building materials,
and the restoration of degraded land.

The change in carbon stock can be estimated using the forest inventory
methods described in this section. However, agroforestry can also affect
energy-related emissions from farm and irrigation equipment, biological
emissions from soil disturbance and livestock, emissions related to the
production and use of fertilizer, and emissions related to fuel wood
use. Reporters should consult the Technical Guidelines for other sectors
such as agriculture and energy to estimate those effects.

Agroforestry activities are made up of a wide range of interdependent
actions. While substantial research has been conducted to evaluate
various agroforestry activities, it is not clear to what extent the
results of the research can be generalized to assist in evaluating other
activities. In the face of the difficulties associated with estimating
activity effects, a more credible report may result if the analysis is
limited to the most certain of the effects, such as carbon sequestration
by trees and soils.

##### 1.I.4.3 Forest Management

It may be possible to modify the management regimes of existing forests
to increase their carbon stocks. Management decisions regarding
objectives can be made at any and all stages in a rotation. Activities
may be applied either during the period of forest growth (intermediate
forest treatments) or at the time of harvest and regeneration.

Intermediate treat­ments include, but are not limited to, the following:

-   Species composition control

-   Pre-commercial thin

-   Commercial thin

-   Management of hazardous fuels

-   Firewood harvests

-   Fertilization

-   Prescribed fire

-   Changing the rotation length

These activities may increase (or decrease) carbon stocks, although the
effects of various treatments tend to be highly site-specific. As a
consequence, it may not be possible to use generalized methods for
site-specific estimation, and reporters will need to develop specific
methods and have them certified for use in their report. Entities
developing new methods must follow the guidance provided in Chapter 1,
Part A, Section A.4 of the Technical Guidelines.

Increases in carbon stocks may also be possible by altering the
processes used to harvest and regenerate the forest site. Logging
techniques and utilization standards influence the amount of residual
material left in the forest to decompose and the survivability of
residual trees. In addition, techniques used to prepare and encourage
forest regeneration, such as prescribed burning, can release greenhouse
gases. Site preparation techniques include the following:

• Site preparation burning

• Mechanical site preparation

• Chemical site preparation.

Forest management may also include a decision to preserve a forest that
has previously been treated in some other way. Forest preservation may
involve protecting existing forests from harvest or conversion to other
land use or uses. Preserved forests will continue to be affected by
natural disturbances. Although the net change in carbon stocks from
preservation is expected to be positive, the result depends upon the
effects of natural disturbance on all of the forest carbon pools. An
entity may choose to report and register the preservation of existing
terrestrial carbon stocks as a forest management practice if
restrictions are placed on the land to ensure that human-caused releases
of carbon do not occur in the future. Options include permanent
conservation easements and deed restrictions.

Changes in carbon stocks for managed forests are estimated using the
approach described in Section 1.I.2. Reporters may choose among the
standard estimation methods: periodic field measurements, computer
models, or look-up tables Estimating changes in carbon stocks in
response to specific forest management practices using models or look-up
tables is not possible in all cases, because currently there is little
quantitative information available about how specific forest management
activities affect all ecosystem carbon pools. Periodic direct
measurement may currently provide the only viable approach, although
research on the effects of forest management on the carbon cycle is
progressing and appropriate models and lookup tables may become
available in the future. Wood products may be part of the forest
management regime. How to treat wood products as part of forest
management is addressed separately in Section 1.I.4.5.

##### 1.I.4.4 Short-Rotation Biomass Energy Plantations

For estimating changes in carbon stocks, biomass energy plantations
occupy an intermediate position between forestry and annual agriculture.
With woody biomass crops, harvesting occurs approximately every 5 to 12
years, and regeneration is often accomplished by coppice methods that
rely on the regrowth of new stands from the root stock of the harvested
stand. Regeneration may also involve the planting of genetically
improved planting stock. Reporters should be careful to consider the
effects of biomass energy plantations on all of the forest ecosystem
carbon pools.

The principal effect of a biomass energy activity is to displace fossil
energy with biomass energy, thereby reducing fossil-fuel carbon
emissions to the atmosphere. Reporters should also account for
fossil-fuel emissions from the harvesting and transportation of the
biomass fuel. For guidance in making estimates, reporters should consult
the Technical Guidelines for the electricity supply sector regarding
emissions from biomass fuels and the displaced fossil fuels.

##### 1.I.4.5 Wood Products

There are several kinds of activities that result in the production of
wood products, which may be part of a forest management regime or result
from manufacturing processes. Wood may also be burned for energy as a
substitute for use of fossil fuels, and wood products may be substituted
for other products. This subsection addresses only the production of
wood products as part of a forest management regime. Use of wood for
energy is addressed in Section 1.I.4.4 and in Technical Guidelines for
the energy sector. Substitution of manufactured products is covered by
the Technical Guidelines for the manufacturing sector.

Several of the activities discussed in this subsection could involve the
harvest of timber or pulpwood for use in wood products. Studies have
indicated that the carbon contained in harvested trees follows several
different paths after harvest, with some remaining in wood products for
only a short time (1 to 5 years), but a significant amount remaining for
decades before returning to the atmosphere. Some of the carbon may be
recycled or stored in landfills after the initial wood-product use is
discontinued.

Tracking carbon in wood products requires a different approach than
tracking carbon in forest ecosystems. Acceptable approaches are
described in subsection 1.I.2.5.4.

##### 1.I.4.6 Urban Forestry

Urban forestry activities can have two principal effects on greenhouse
gas emissions and changes in carbon stocks. One is increased carbon
sequestration through tree growth. As with all forestry activities,
urban trees sequester carbon in above and belowground components, and
may also contribute to increasing carbon stocks in soils. Urban trees,
however, may require maintenance efforts such as trimming and leaf
collection that need to be factored into the estimates.

The other principal effect is the avoidance of greenhouse gas emissions
through energy conservation. Simulation models indicate that
strategically located trees may provide two kinds of effects in this
regard. One is through increased shading during peak cooling periods
(deciduous trees conveniently cast a great deal of shade during the
growing season and much less during the winter). The other effect
results from establishment of a windbreak (often provided by conifers)
that reduces fuel use during winter heating months. The location of the
trees relative to the targeted building is a critical factor.

The estimation of carbon stocks and changes in carbon stocks is directly
analogous to that described for forest management activities---that is,
changes in carbon stocks by trees is measured as the net increase
relative to the previous land use (for example, lawn). The estimates
should account for both above- and below-ground components and all
relevant tree maintenance activities.

The guidance provided in this document is most appropriate for land
areas that meet the definition of forest. In contrast, urban trees are
often managed as single trees rather than forest trees, and so the
methods must be adapted. Although the estimation approach is the same
for urban and rural forests, the specific data and models are likely to
be different. In general, the guidance provided for measuring changes in
carbon stocks can be used for urban street trees, but sampling methods
should be carefully reviewed and possibly revised for efficient
application in an urban setting. There are several models available for
estimating the changes in carbon stocks for urban trees. Reporters
should follow the modeling guidelines to evaluate whether a specific
model is appropriate for use. The current forestry guidelines do not
provide look-up tables for urban trees.

Estimating reductions in greenhouse gas emissions through energy
conservation can be a complicated endeavor because many factors are
variable over the life of the activity. One source of variation is
climate---the temperature regime differs from year to year. Another
source is additional modifications in the building that may influence
energy consumption (and the energy-saving contribution of trees).
Entities interested in reporting greenhouse gases and registering
reductions associated with the energy savings activities should refer to
those sections of the Technical Guidelines pertaining to the residential
and commercial buildings sector.

**Technical Guidelines for Voluntary Reporting of Greenhouse Gases
Program**

## Chapter 2, Emission Reductions

Outline

# 

2.1. Introduction

2.2. Calculating Emission Reductions

> 2.2.1. Section 300.8 of the General Guidelines

2.2.2. Choosing Appropriate Emission Reduction Calculation Methods

2.2.3. Identifying Subentities for which Reductions are Calculated

2.3. Base Periods and Base Values

2.3.1. Choosing a Base Period for Calculating Reductions

2.3.2. Establishing Base Values

2.3.3. When to Recalculate or Establish a New Base Value

###  {#section-25 .Normal-+-Times-New-Roman}

2.4. Technical Guidelines for the Application of Specific Calculation
Methods

> 2.4.1. Changes in Emissions Intensity
>
> 2.4.2. Changes in Absolute Emissions
>
> 2.4.3. Changes in Carbon Storage
>
> 2.4.4. Avoided Emissions
>
> 2.4.5. Action-Specific Calculation Methods
>
> 2.4.6. Estimating Reductions Associated with Energy Generation and
> Distribution

2.5. Determining Registered Emission Reductions

2.6. Revising Previously Accepted Reports of Emission Reductions

### 2.1 Introduction

This Chapter, Emission Reductions, provides draft Technical Guidelines
and explanatory materials that are directly relevant to the emission
reductions guidelines contained in Section 300.8 of the revised General
Guidelines. An excerpt of Section 300.8 is provided below, followed by
the Emission Reduction Guidelines relevant to this section and
explanatory information and examples as needed.

The Energy Information Administration (EIA) will develop the forms and
instructions necessary for reporters to participate in the program.
Those forms and instructions will be designed to implement both the
General Guidelines and the Technical Guidelines.

### 2.2 Calculating Emission Reductions

#### 2.2.1 Section 300.8 of the General Guidelines

*Excerpt from the General Guidelines, section 300.8, Calculating
emission reductions:*

*(a) [Choosing appropriate emission reduction calculation
methods.]{.underline}*

*(1) An entity must choose the method or methods it will use to
calculate emission reductions from the list provided in paragraph (h) of
this section. Each of the calculation methods has special
characteristics that make it applicable to only certain types of
emissions and activities. An entity should select the appropriate
calculation method based on several factors, including:*

*(i) How the entity's subentities are defined;*

*(ii) How the reporter will gather and report emissions data; and*

*(iii) The availability of other types of data that might be needed,
such as production or output data.*

*(2) For some entities, a single calculation method will be sufficient,
but many entities may need to apply more than one method because
discrete components of the entity require different calculation methods.
In such a case, the entity will need to select a method for each
subentity (or discrete component of the entity with identifiable
emission or reductions). The emissions and output measure (generally a
physical measure) of each subentity must be clearly distinguished and
reported separately. Guidance on the selection and specification of
calculation methods is provided in Chapter 2 of the Technical Guidelines
(incorporated by reference, see §300.13).*

*(b) [Identifying subentities for calculating reductions]{.underline}.
If more than one calculation method is to be used, an entity must
specify the portion of the entity (the subentity) to which each method
will be applied. Each subentity must be clearly identified. From time to
time, it may be necessary to modify existing or create new subentities.
The entity must provide to EIA a full description of such changes,
together with an explanation of why they were required.*

*(c) [Choosing a base period for calculating reductions]{.underline}. In
general, the base period used in calculating emission reductions is the
single year or up to four-year period average immediately preceding the
first year of calculated emission reductions.*

*(d) [Establishing base values]{.underline}. To calculate emission
reductions, an entity must establish a base value against which to
compare reporting year performance. The minimum requirements for base
values for each type of calculation method are specified in Chapter 2 of
the Technical Guidelines (incorporated by reference, see §300.13). In
most cases, an historic base value, derived from emissions or other data
gathered during the base period, is the minimum requirement specified.
Entities may, however, choose to establish base values that are more
stringent than the base values derived from the methods specified in
Chapter 2 of the Technical Guidelines as long as their report indicates
the rationale for the alternative base value and demonstrates that it
would result in a smaller quantity of emission reductions.*

*(e) [Emission reduction and subentity statements]{.underline}. For each
subentity, an entity must submit to EIA the following information:*

*(1) An identification and description of the method used to calculate
emission reductions, including:*

*(i) The type of calculation method;*

*(ii) The measure of output used (if any); and*

*(iii) The method-specific base period for which any required base value
will be calculated.*

*(2) The base period used in calculating reductions. When an entity
starts to report, the base period used in calculating reductions must
end in the start year. However, over time the reporting entity may find
it necessary to revise or establish new base periods and base values in
response to significant changes in processes or output of the
subentity.*

*(3) A description of the subentity and its primary economic activity or
activities, such as electricity generation, product manufacturing,
service provider, freight transport, or household operation; and*

*(4) A description of the emission sources or sinks covered, such as
fossil fuel power plants, manufacturing facilities, commercial office
buildings or heavy-duty vehicles.*

*(f) [Changes in calculation methods, base periods and base
values.]{.underline} When significant changes occur in the composition
or output of reporting entities, a reporting entity may need to change
previously specified calculation methods, base periods or base values. A
reporting entity should make such changes only if necessary and it
should fully document the reasons for any changes. The Technical
Guidelines (incorporated by reference, see §300.13) describe when such
changes should be made and what information on such changes must be
provided to DOE. In general, such changes should not result in any
alterations to previously reported or registered emission reductions. A
reporting entity may alter previously reported or registered emission
reductions only if necessary to correct significant errors.*

*(g) [Continuous reporting]{.underline}. To ensure that the summation of
entity annual reports accurately represents net, multi-year emission
reductions, an entity must submit a report every year, beginning with
the first reduction year. An entity may use a specific base period to
determine emission reductions in a given future year only if the entity
has submitted qualified reports for each intervening year. If an
interruption occurs in the annual reports of an entity, the entity must
subsequently report on all missing years prior to qualifying for the
registration of additional emission reductions.*

*(h) [Calculation methods.]{.underline} An entity must calculate any
change in emissions, avoided emissions or sequestration using one or
more of the methods described in this paragraph and in the Technical
Guidelines (incorporated by reference, see §300.13).*

*(1) [Changes in emissions intensity]{.underline}. An entity may use
emissions intensity as a basis for determining emission reductions as
long as the entity selects a measure of output that is:*

> *(i) A reasonable indicator of the output produced by the entity;*
>
> *(ii) A reliable indicator of changes in the entity's activities;*
>
> *(iii) Related to emissions levels; and*

*(iv) Any appropriate adjustments for acquisitions, divestitures,
insourcing, outsourcing, or changes in products have been made, as
described in the Technical Guidelines (incorporated by reference, see
§300.13).*

*(2) [Changes in absolute emissions]{.underline}. An entity may use
changes in the absolute (actual) emissions (direct and/or indirect) as a
basis for determining net emission reductions as long as the entity
makes only those adjustments required by the Technical Guidelines
(incorporated by reference, see §300.13). An entity intending to
register emission reductions may use this method only if the entity
demonstrates in its report that any reductions derived from such changes
were not achieved as a result of reductions in the output of the entity,
and certifies that emission reductions are not the result of major
shifts in the types of products or services produced. Entities may
report, but not register, such reductions even if the output associated
with such emissions is declining.*

*(3) [Changes in carbon storage (for actions within entity
boundaries)]{.underline}. An entity may use changes in carbon storage as
a basis for determining net emission reductions as long as the entity
uses estimation and measurement methods that comply with the Technical
Guidelines (incorporated by reference, see §300.13), and has included an
assessment of the net changes in all sinks in its inventory.*

*(4) [Changes in avoided emissions (for actions within entity
boundaries]{.underline}). An entity may use changes in avoided emissions
to determine its emission reductions. Avoided emissions eligible to be
included in the calculation of net emission reductions that qualify for
registration include those associated with the sale of electricity,
steam, hot water or chilled water generated from non-emitting or
low-emitting sources as a basis for determining net emission reductions
as long as:*

*(i) The measurement and calculation methods used comply with the
Technical Guidelines (incorporated by reference, see §300.13);*

*(ii) The entity certifies that any increased sales were not
attributable to the acquisition of a generating facility that had been
previously operated, unless the entity's base period includes generation
values from the acquired facility's operation prior to its acquisition;
and*

*(iii) Generators of distributed energy that have net emissions in their
base period and intend to report reductions resulting from changes in
eligible avoided emissions, use a method specified in the Technical
Guidelines (incorporated by reference, see §300.13) that integrates the
calculation of reductions resulting from both changes in emissions
intensity and changes in avoided emissions.*

*(5) [Action-specific emission reductions (for actions within entity
boundaries).]{.underline} A number of source- or situation-specific
methods are provided in the Technical Guidelines and these methods must
be used to assess the annual changes in emissions for the specific
sources or situation addressed by these methods. In addition, a generic
action-specific method is identified in the Technical Guidelines. An
entity intending to register reductions may use the generic
action-specific approach only if it is not possible to measure
accurately emission changes by using one of the methods identified in
paragraphs (h)(1) through (h)(4) of this section. Entities that intend
to register reductions and that use the generic action-specific approach
must explain why it is not possible to use any of these other methods.
An entity not intending to register reductions may use the generic
action-specific method to determine emission reductions, as long as the
entity demonstrates that the estimate is based on analysis that:*

*(i) Uses output, utilization and other factors that are consistent, to
the maximum extent practicable, with the action\'s actual performance in
the year for which reductions are being reported;*

*(ii) Excludes any emission reductions that might have resulted from
reduced output or were caused by actions likely to be associated with
increases in emissions elsewhere within the entity\'s operations; and*

*(iii) Uses methods that are in compliance with the Technical Guidelines
(incorporated by reference, see §300.13).*

*(i) [Summary description of actions taken to reduce
emissions]{.underline}. Each reported emission reduction must be
accompanied by an identification of the types of actions that were the
likely cause of the reductions achieved. Entities are also encouraged to
include in their reports information on the benefits and costs of the
actions taken to reduce greenhouse gas emissions, such as the expected
rates of return, life cycle costs or benefit to cost ratios, using
appropriate discount rates.*

*(j) [Emission reductions associated with plant closings, voluntary
actions and government (including non-U.S. regulatory regimes)
requirements]{.underline}.*

*(1) Each report of emission reductions must indicate whether the
reported emission reductions were the result, in whole or in part, of
plant closings, voluntary actions, or government requirements. EIA will
presume that reductions that were not the result of plant closings or
government requirements are the result of voluntary actions.*

*(2) If emission reductions were, in whole or in part, the direct result
of plant closings that caused a decline in output, the report must
identify the reductions as such; these reductions do not qualify for
registration. EIA will presume that reductions calculated using the
emissions intensity method do not result from a decline in output.*

*(3) If the reductions were associated, in whole or part, with U.S. or
non-U.S. government requirements, the report should identify the
government requirement involved and the effect these requirements had on
the reported emission reductions. If, as a result of the reduction, a
non-U.S. government issued to the reporting entity a credit or other
financial benefit or regulatory relief, the report should identify the
government requirement involved and describe the specific form of
benefit or relief provided.*

*(k) [Determining the entity responsible for emission
reductions]{.underline}. The entity that EIA will presume to be
responsible for emission reduction, avoided emission or sequestered
carbon is the entity with financial control of the facility, land or
vehicle which generated the reported emissions, generated the energy
that was sold so as to avoid other emissions, or was the place where the
sequestration action occurred. If control is shared, reporting of the
associated emission reductions should be determined by agreement between
the entities involved so as to avoid double-counting; this agreement
must be reflected in the entity statement and in any report of emission
reductions. EIA will presume that an entity is not responsible for any
emission reductions associated with a facility, property or vehicle
excluded from its entity statement.*

#### 2.2.2 Choosing Appropriate Emission Reduction Calculation Methods

The enhanced reporting program emphasizes entity-wide assessments of
emission reductions rather than those resulting from discrete projects
or other actions affecting only part of an entity\'s total emissions.
Because many reporting entities are likely to encompass a variety of
operations (e.g., manufacturing, offices, warehouses, leased fleets,
land management), the Guidelines provide considerable flexibility in the
selection and application of specific methods used to calculate emission
reductions. For example, a manufacturing company may choose to use
emissions-intensity methods to calculate reductions, but may produce
different products that are unable to be measured by a single fungible
unit such as tons. Such a company may therefore need to divide its
operations into subentities to facilitate the assessment and reporting
of greenhouse gas emission reductions from its various lines of
business.

Segmenting the entity into subentities provides reporters the
flexibility to use alternative approaches in calculating changes in
emissions. For example, it may be desirable to assess the emission
reductions associated with some business lines using changes in absolute
emissions (if output is flat or increasing), and in others by using one
or more intensity metrics. Large emitters seeking to register emission
reductions should attempt to assess all their changes in emissions using
the fewest number of methods feasible, but may use as many methods as
necessary.

Before beginning to report, an entity must select the method or methods
it will use to calculate emission reductions. This selection process
will determine the definition of the entity's subentities, how it will
gather and report emissions data, and what other types of data - such as
product production or other forms of output - will have to be gathered.
If two or more calculation methods are selected, the entity must define
distinct subentities, one for each method chosen. The emissions and
usually the physical or economic measure of the output of each subentity
must be clearly distinguished and reported separately.

The five basic calculation methods identified in the revised General
Guidelines are designed as a group to enable entities to calculate the
emission reductions associated with virtually any type of emission
source and activity. No single methodology could achieve this objective
on its own. Each methodology has special attributes that make it
appropriate for use in some situations but not in others, and each
encompasses a range of specific calculation methods or formulas that may
make them uniquely applicable to specific entities or subentities. While
some entities may be able to use one of the five methods to assess all
their year-to-year changes in emissions or carbon sequestration, it is
more likely that entities will need to use multiple methods to complete
an entity-wide assessment.

The applicability of each of the five methods is discussed in the
following five subsections. Most large emitters seeking to register
emission reductions are likely to choose either emissions intensity or
absolute emissions as their primary method of calculating emission
reductions. Electricity generators and other producers of energy that
report emissions associated with distributed energy during their Base
Period must use an integrated method (described in subsection 2.4.6)
that combines the emissions intensity and avoided emissions methods, or
use the absolute-emissions method (specified in subsection 2.4.2 of this
Chapter). Entities that generate and distribute energy that report no
emissions associated with such distribution of energy in their Base
Period should use just the avoided emissions method (described in
subsection 2.4.4).

##### 2.2.2.1 Changes in Emissions Intensity

Entities are encouraged to calculate reductions using
emissions-intensity methods when feasible. Using emissions-intensity
methods is usually feasible when the following are applicable:

-   There is a clear physical measure of the output associated with, or
    the service provided by, the emissions.

-   The same measure of output is likely to be used for at least several
    years (that is, the basic product being produced, the output metric,
    is not likely to change substantially in the near future).

-   It is not likely that significant elements of the covered process
    will be outsourced (or "in-sourced") in the near future.

A single measure of output and emissions intensity might, in some cases,
be able to account for all of an entity\'s emissions, including both
those associated directly with the entity\'s production process and
those other emissions associated with providing managerial or logistical
support to the production process. It is likely, however, that many
entities will need more than one measure of output and emissions
intensity to complete a comprehensive assessment of their annual changes
in emissions. See subsection 2.4.1 for guidelines on applying this
method.

##### 2.2.2.2 Changes in Absolute Emissions

Any entity may use changes in the quantity of their absolute emissions
(for the entity as a whole or a specific subentity) to determine
emission reductions to be reported to EIA. However, entities that intend
to register their reductions may use this method only *if* they can
demonstrate that the output associated with covered emissions did not
decline from the identified base period to the reporting year. Entities
may use one or more physical or economic measures of output (such as
quantity of product or total value of shipments) to demonstrate that the
affected output has not declined. Tables 2.1 on page 266 and 2.2 on page
268 list some of the possible output measures that might be used to
demonstrate that output has not declined. When the output associated
with the reported emissions has not declined, the resulting emission
reductions would be equal to or less than the amount calculated by an
emissions-intensity method, assuming the same measures of output were
used. This approach may be used even if it is feasible to use an
emissions-intensity method.

Entities that do not intend to register reductions or that wish to
supplement their report of registered reductions with a separate
subentity report of the reductions in their absolute emissions may use
this method even if the output associated with the covered emissions has
declined since the identified base period. See subsection 2.4.2 for
guidelines on applying this method.

##### 2.2.2.3 Changes in Carbon Storage 

This method is to be used whenever the emission reductions (or
increases) are associated with changes in the quantity of carbon stocks.
Changes in carbon-stock quantities may occur in forests and agricultural
soils, wood products, and in geologic carbon sequestration. The
year-to-year changes in each distinct type of carbon storage must be
estimated independently. Entities may use multiple-year averages for
estimating annual carbon fluxes as long as the approaches are consistent
with inventory guidance provided in Chapter 1. Because geologic
sequestration is associated with the capture of anthropogenic emissions
that are the responsibility of the reporting entity, emission reductions
associated with changes in geologic sequestration should be assessed as
an integral part of an entity's assessment of the affected emissions.
See subsection 2.4.3 for guidelines on applying the Changes in Carbon
Storage method.

##### 2.2.2.4 Changes in Avoided Emissions 

Avoided emissions occur when an energy product (including electricity,
hot water, steam, and chilled water) produced by a non- or low-emitting
source is distributed to customers that would have otherwise purchased a
comparable energy product generated by a higher-emitting source. This
method may be used alone or exclusively only if the reporting entity has
no emissions associated with such energy exports in their base period;
that is, either all of its distributed energy were generated by
non-emitting sources or it distributed no energy during its chosen base
period. In most cases, reductions associated with distributed energy are
calculated using a method that combines changes in emissions intensity
and avoided emissions, or by calculating changes in absolute emissions.
See subsection 2.4.2 for guidelines on applying this method. In
addition, see subsection 2.4.6 for more specific guidance on the
calculation of emission reductions by energy exporters.

##### 2.2.2.5 Action-Specific Emission Reductions

This category encompasses a range of methods designed to assess the
emission reductions that result from specific actions not covered by any
other methods described. For those entities intending to register
reductions based on an entity-wide assessment of their emission changes,
action-specific calculation methods should be used only if none of the
other methods is feasible. Some of the situations in which
action-specific methods might be needed include:

-   Entities (or subentities) that cannot use emission-intensity methods
    and are experiencing declining production.

-   Special emission-reduction categories, such as methane recovery from
    landfills or coal mining.

-   Small emitters that are reporting on a specific activity.

-   Emission reductions reported, but not registered, by entities.

Regardless of the method chosen, the end result will be an estimate of
the emission reductions in the form of tons of carbon dioxide (CO~2~)
equivalent for the year being reported. Technical guidance on how to
apply each of these methods is provided in subsection 2.4.5.

#### 2.2.3 Identifying Subentities for which Reductions are Calculated

If an entity intends to use more than one method of calculating emission
reductions or more than one output measure to calculate changes in
emissions intensity, it must identify a distinct subentity for each
method or output metric used. Creating a subentity is a way to apportion
the entity into discrete sets of emission sources or sinks, each
associated with identifiable output. For example, an entity may have two
lines of business producing two very different types of products. It
might choose to calculate its emission reductions associated with both
business lines using the emissions-intensity method, but because it
would use two different measures of output, it must define a distinct
subentity for each line of business. Another entity may be able to use
absolute emissions as its primary method of determining emission
reductions, but would still need to create distinct subentities if it
chose to register reductions associated with terrestrial carbon storage,
such as forestry-related sequestration occurring on its land.

##### 2.2.3.1 Defining Subentities for Large Emitters

To register emission reductions, large emitters must attempt to
determine their net entity-wide emission reductions using one or more of
the five calculation methods specified in the General Guidelines. To
complete an entity-wide assessment of emission reductions, the sum of
the emissions of all subentities must equal the sum of the emissions for
the entire entity, excluding *de minimis* sources. In the case where the
entity has emissions for which no assessment of emission reductions is
possible, the entity must report those emissions for one or more
distinct subentities and provide an explanation of why no assessment of
reductions for those emissions was feasible.

Two or more subentities may share a physical emission source, provided
that in preparation of the reporter's emissions inventory, the emissions
from the shared source are allocated to each subentity using a method
that accurately reflects the subentity's share of the
emissions-producing activity or activities associated with that source.

Each subentity for which emission reductions will be calculated using
the emissions-intensity method must be associated with a distinct output
measure. Two subentities may not use an identical output measure unless
the subentities are using different base periods to calculate emission
reductions (see Section 2.3, "Base Periods and Base Values").

If a reporter wishes to use the absolute-emissions method to calculate
emission reductions for part of its entity, that part of the entity
should be reported as a single subentity, unless sources within that
part of the entity must use a different base period to calculate
emission reductions (see Section 2.3, "Base Periods and Base Values").

If action-specific methods are used, each method used must be applied to
emissions and emission reductions that are defined as a distinct
subentity.

##### 2.2.3.2 Defining Subentities for Small Emitters

Small emitters that want to register emission reductions must determine
the net reductions associated with each activity (e.g., forestry,
building operations, tillage, wind power) on which they have decided to
report. It is likely that the emission reductions associated with a
specific activity will be able to be calculated using a single method.
In such cases, the entity would define a single subentity for each
activity covered by its report. If more than one method is used, a
distinct subentity should be defined for each method. The requirements
governing the definition of individual subentities are the same for both
large emitters and small emitters.

##### 2.2.3.3 Modifying or Adding Subentities

A reporter may modify an existing subentity included in a previous
report or add a new subentity to accommodate a change in the method used
to estimate emission reductions. In particular, a subentity may be
modified or split into two or more subentities if the reporter
determines that changes in the subentity's products or services make it
necessary to use one or more new output measure.

A reporter also may add a new subentity if the reporter has established
a new, or acquired an existing, business unit that requires a different
method or output measure for calculating emission reductions. For
further guidance on how to treat new or acquired business units, see the
guidance provided for the applicable emission reduction calculation
method (see also guidance on establishing a new base period or new base
value in subsection 2.3.3).

##### 2.2.3.4 Information on Each Subentity to be Submitted to EIA

The following are the categories of information on each subentity that
must be submitted to EIA:

-   Name of the subentity (any logical name)

-   Location(s)

-   Identification of basis for subentity boundaries

-   Description of primary activities

-   Description of primary emission sources

-   Emission-reduction calculation method

-   Output measure used (if any)

-   Base period

-   Base value and data used to derive base value (e.g., emissions,
    output)

-   Reporting-year emissions or carbon sequestration

-   Emission reductions in reporting year and data used to calculate
    emission reductions (e.g., emissions, output, carbon sequestration)

-   If the subentity is added after the entity begins to report,
    indicate whether the subentity was previously covered by any other
    reports to the 1605(b) Program and whether the subentity's primary
    activity is new or existed previously

### 2.3 Base Periods and Base Values

#### 2.3.1 Choosing a Base Period for Calculating Reductions

When beginning to report, the first year of calculated (registered or
reported) reductions must be the year immediately following the Start
Year (see § 300.5, "Submission of an entity statement," in the General
Guidelines). Consequently, the base period from which those reductions
are calculated must be, or must end with, the Start Year.

All emission reductions are calculated relative to an identified base
value.[^177] In most cases, participants are required to use base values
that are derived from the emissions (and related quantities of output or
demand) that occurred during the identified base period (the average
annual value if the base period is more than one year). For each
distinct emission-reduction method used, the entity must determine an
appropriate base period. Choosing a one-year base period may simplify
the process of starting to report reductions, but choosing the average
annual emissions over a base period of 2 to 4 years is more likely to
result in a base value that is less affected by annual variations in
factors, such as weather, that are not within the control of the entity.

All base periods must end in the Start Year. If a one-year base period
is used to derive the base value, that year must be the same as the
Start Year. If a multi-year base period is used to derive the base
value, the last year of the initial base period must be the Start Year.

In all cases, the first emission-reduction calculation (reported or
registered) must occur in the year immediately following the base period
(i.e., the First Reduction Year). For those entities intending to
register their emission reductions, the last year of the chosen base
period must not be earlier than 2002 unless the entity has an existing
commitment under the Climate Leaders or Climate VISION programs (see
General Guidelines, Section 300.1(c),(1)). For entities that wish to
report (but not register) reductions, the last year of the chosen base
period must be no earlier than 1990.

The following examples illustrate the determination of base period:

*Example 1.* If a reporter submits a report to register reductions
achieved in 2003, the reporter could use one of the following base
periods:

-   1 year: 2002

-   2 years: 2001 and 2002

-   3 years: 2000, 2001, and 2002

-   4 years: 1999, 2000, 2001, and 2002

Unless significant changes occurred in the entity or subentity covered
by this emission-reduction calculation, the reporter would continue to
use the same base period in all future emission-reduction calculations
(e.g., 2004, 2005, 2006).

*Example 2.* If a reporter wants to begin reporting emission reductions
for 2004, its Start Year (and last year of any base period) would have
to be 2003.

*Example 3.* If a reporter wants to begin reporting on reductions that
are not to be registered, the Start Year and the last year of the
initial base period must still be the year immediately preceding the
first year of any reported reductions. In this case, the base period
could be as early as 1990 (if the first year of reported reductions was
1991). Alternatively, the reporter would be able to use any 2-, 3-, or
4-year base period, as long as it ended in the chosen Start Year.

Reporters should note that the Reporting Year is the year for which the
emission-reduction calculation (reported but not registered or
registered) was performed, and not the calendar year in which the report
is being submitted. As explained above, the first Reporting Year is
always the year after the Start Year. Depending upon a reporter's
particular set of circumstances (registering, reporting but not
registering, and participation in Climate Leaders or Climate Vision),
there are a number of reports that could potentially be submitted at the
initiation of the revised Program.[^178]

#### 2.3.2 Establishing Base Values

In order to calculate the emission reductions to be registered or
reported under 1605(b), reporters must establish a base value against
which to compare reporting-year performance, except in a small subset of
action-specific reductions outlined in subsection 2.4.5. The base value
may take any one of several different forms, including an historic
emissions level, quantity of terrestrial carbon stocks, an historic
emissions intensity, or a benchmark emissions intensity against which
the reporting-year emissions level or emissions intensity is compared.
Benchmarks are either specified by the Department of Energy (DOE) or
calculated by the reporter in accordance with DOE guidelines.

Each of the five methods for calculating emission reductions uses a
different type of Base Value:

-   For changes in emissions intensity, the Base Value will usually be
    in the form of actual annual emissions in the Base Period per unit
    of annual output in the base period (or annual averages if the Base
    Period is more than one year).

-   For changes in absolute emissions, the Base Value will usually be
    the actual amount of annual emissions in the base period (or an
    average amount if the Base Period is more than one year).

-   For changes in terrestrial carbon storage resulting from
    agricultural or forestry sequestration, the base value is the prior
    year's carbon stock.[^179]

-   For those energy exporters using changes in avoided emissions only,
    the Base Value is the appropriate emissions intensity benchmark
    specified by DOE. For those energy exporters using changes in
    avoided emissions combined with intensity, the Base Value is derived
    from the quantities of electricity or other energy exported in the
    base period (or the average annual quantity distributed if the base
    period is more than one year) and any associated emissions, plus the
    incremental quantity of energy exported in Reporting Year and the
    emissions for this quantity derived from the appropriate intensity
    benchmark specified by DOE.

-   For action-specific emission reductions, the Base Value can be
    either the estimated amount of total emissions or emissions
    intensity of the subject technology or process extant in the base
    period (whenever these values are estimated based on characteristics
    of the extant technology or process, a multi-year base period is
    unnecessary and should not be used).

In all cases, the minimum Base Value must be the value calculated using
the entity's (or subentity's) actual emissions, output or other base
period performance data. After calculating the minimum Base Value using
actual base period emissions and other performance data, entities may
choose to establish and use Base Values that are more stringent, i.e.,
that would result in fewer emission reductions. In such cases, reporters
must report the minimum Base Value, as well as identify and describe the
basis for the more stringent base value used in its emission reduction
calculation.

Over time, Base Values may need to be recalculated or changed to reflect
subsequent acquisitions, divestitures, or other significant changes that
occur to the entity. The guidelines for such changes are described
below. In addition, if an entity improves its emissions-inventory
methods and is able to revise its base-period emissions values to
reflect the improvements, those changes should also be incorporated in
any base values that are affected. Note that if such revisions are made,
they will be applied only to current and future reports, not to
previously calculated and reported emission reductions.

#### 2.3.3 When to Recalculate or Establish a New Base Value

Once established, a base value should not be changed unless significant
changes occur in the make-up of the entity and its production processes,
or in the characteristics of its product or output. If warranted,
however, there are two types of changes that can, and sometimes must, be
made to a base value:

1)  *Recalculating Base Values:* Base-period emissions, carbon stocks,
    and/or output quantities should be recalculated to reflect certain
    significant changes in the entity or significant improvements in
    emission or sequestration estimation methods that occurred since the
    base value was established; or

2)  *Establishing a New Base Period:* A new (more recent) base period
    must be established if recalculation of the base value is not
    possible and significant changes have occurred in the make-up of the
    entity and its production processes, or in the characteristics of
    its product or output. When a new base period has been established,
    a new base value must then be calculated.

Entity changes occurring on or before May 31 of a given calendar year
that require changes to base values or base periods must be reflected in
the report submitted covering emissions and reductions for the following
calendar year. Reporters may choose to postpone incorporating changes to
base values or base periods if the forcing entity changes occurred after
May 31 until submitting the report covering emissions and reductions for
the year after the following calendar year. This grace period of at
least 12 months is provided to allow reporters sufficient time to
integrate data management systems to enable recalculation of base values
to reflect the reconfigured entity and new base period. The
recalculation of new base values or establishment of a new base period
should not result in a gap in the entity's annual reporting. Such
revisions may not be used as the basis for revised prior year reports of
emission reductions.

##### 2.3.3.1 Recalculating Base Values

Over time, an entity or subentity may undergo a variety of changes that
result in the transfer of emission sources and/or sinks, making it
difficult to determine actual changes in emissions intensity (or
absolute emissions). Those changes could include mergers, acquisitions,
divestitures, and the outsourcing or insourcing of significant elements
of the production process. An entity might also change the methods used
to measure its greenhouse gas emissions, especially if the entity has
developed more accurate methods since the emissions were initially
estimated. If such changes are likely to distort the calculation of
emission reductions, the entity should first attempt to eliminate or
minimize such distortions by recalculating the base values from which
emission reductions are calculated.

**2.3.3.1.1 Acquisitions and Divestitures**

An entity or subentity that gains or loses significant sources of
emissions through a merger, acquisition, or divestiture must adjust its
base value of emissions to reflect this transfer, if the historical
records of the affected units are available and such an adjustment is
feasible. A significant source is defined as one representing 3 percent
or more of emissions measured in units of carbon dioxide equivalent
(CO~2~e) in the base period. Acquired entities should only be
incorporated into a previously established Base Value if they existed in
the relevant Base Period of the acquiring entity and the required
emissions and output data is available and is reported to EIA. In
general, such adjustments should be made only on the basis of a full
year of performance data, although base-period emissions may need to be
adjusted on a pro rata basis if the merger, acquisition, or divestiture
occurs in the middle of the year.

An entity or subentity using an intensity Base Value may choose not to
adjust Base-Period emissions if the emissions gained or lost in the
transfer of the source(s) also resulted in a corresponding and
commensurate gain or loss of output. For purposes of this guidance, a
commensurate gain or loss of output shall be determined as an increase
or decrease that is within 3 percent of the percentage increase or
decrease in the entity's or subentity's emissions.

**2.3.3.1.2 Outsourcing/Insourcing**

An entity or subentity that gains or loses significant sources of
emissions through insourcing or outsourcing of particular elements of
its production process must adjust its Base Value of emissions to
reflect this transfer, if adequate records of the affected emissions
exist. Significant sources are defined as those representing 3 percent
or more of emissions measured in units of carbon dioxide equivalence in
the base period. In general, such adjustments should be made only on the
basis of a full year of performance data, although base-period emissions
may need to be adjusted on a pro rata basis if the insourcing or
outsourcing occurs in the middle of the year.

##### 2.3.3.2 Establishing a New Base Period or New Base Value

To the extent possible, an entity should continue to use the same Base
Period and Base Value established in the initial report. However, if
there has been a fundamental change in the entity or subentity, then a
reporter may change the Base Period and Base Value, provided that a
justification is provided and the entity has submitted complete reports
for each year since its original Start Year. DOE anticipates that
resetting the Base Period will be limited to circumstances in which
there has been a fundamental change in the output of an entity or
subentity between the original base period and the reporting year. Those
circumstances include the following:

-   *Creation of a New Business Unit.* The reporting entity creates a
    new business unit composed of one or more new facilities, reports
    emissions for this new business unit as a separate subentity, and
    uses a method and/or output measure to calculate emission reductions
    that is clearly distinct from any other method/output measure used
    by that entity.

-   *Redefining Entities/Subentities.* A reporting entity decides that
    the lines of business of its entire entity or a specific subentity
    have diverged sufficiently that it should be reported as two or more
    subentities. The reporting entity would be permitted to use a
    different Base Period for a subentity that was not included in the
    original base period and for which a new output measure is used to
    measure intensity.

> *Example.* A plastic container manufacturer converts a plant making
> 20-ounce soda bottles to the production of liquid detergent
> containers. The manufacturer decides that the output measure of
> emissions per container used in the original Base Period is no longer
> a comparable output measure with emissions per container after
> conversion to production of liquid detergent containers. The
> manufacturer may reset the Base Period to the first full calendar year
> of producing liquid detergent containers.

-   *Merger of Entities.* A new entity resulting from the merger of two
    or more firms or other entities, at least one of which reported
    previously under the revised 1605(b) guidelines, would be able to
    reset the base period if the merger partners used different base
    periods in reporting previously under 1605(b) and/or one of the
    partners does not have data available for the earlier base period
    originally established by the other merger partner.

> *Example.* A tire manufacturer's plant in the initial base period
> produced only passenger-car tires. The manufacturer expands this plant
> to produce truck tires as well and decides that the number of tires
> produced is no longer an appropriate output measure. For reporting
> purposes, the reporter segments the plant into two subentities. One
> subentity covers the manufacturing of passenger-car tires, retains the
> original base period, and uses the number of passenger-car tires
> produced as the output measure. The second subentity covers the
> manufacturing of truck tires, for which the first full calendar year
> of production becomes the base period and the number of truck tires
> produced is the output measure.

-   *Acquisition of a New Business Line or Subentity Not in Existence in
    the Base Period.* The reporting entity acquires a unit of another
    company that either was not in existence in the reporting entity's
    original base period or for which data are not available for that
    base period.

> *Example.* If a divestiture, acquisition, product change, or other
> development makes the original base value a poor indicator of the
> entity's efforts to reduce emissions and recalculation of the base
> value is not feasible, an entity must choose a new, more current base
> period, and establish a new base value.

[]{.mark}

When changing the base period used by an entity or subentity to
determine the base value of emissions, the new base period should be the
earliest period after the original base period established in the
reporter's first report for which emissions and output data are
available. The reporter may change the number of years in the base
period.

##### 2.3.3.3 Documentation of Changes in Base Periods or Base Values

Whenever a Base Period or Base Value is modified or replaced, the entity
must report to EIA the reasons why a change was necessary, and provide a
rationale for the specific changes made.

### 2.4 Technical Guidelines for the Application of Specific Calculation Methods

The following sections provide guidance on each of the five basic
calculation methods for calculating emission reductions identified in
the General Guidelines: (1) changes in emissions intensity; (2) changes
in absolute emissions; (3) changes in carbon storage; (4) changes in
avoided emissions; and (5) action-specific. Calculating emission
reductions associated with the generation and distribution of
electricity, steam, and hot or chilled water (exported energy) often
requires combining methods for calculating reductions from changes in
intensity with methods for calculating changes in avoided emissions.
Such combined methods are described as part of a special section
(2.4.6).

#### 2.4.1 Changes in Emissions Intensity

Calculating emission reductions based on changes in emissions intensity
is an important objective of the enhanced system for Voluntary Reporting
of Greenhouse Gases. Emissions-intensity methods described in this
section can be used to calculate reductions for a broad range of
entities or subentities.

Depending on the type of output measure(s) chosen, emissions-intensity
methods can be used to calculate changes broadly across a large entity
or, more narrowly, those changes associated with a specific process or
facility. Ideally, the output measure used in developing an
emissions-intensity factor should be a good indicator of year-to-year
changes in the physical and economic output associated with the covered
emissions over a period of many years.

The most important first step should be a review of the potential
measures of output most relevant to an entity's operations and to the
scope of emissions covered by the entity's activities. This section
provides guidance on the types of output measures that should be
considered and the selection criteria to be used, although the
guidelines also allow most entities to choose the output measure that
seems best-fitted to their particular circumstances. Specific guidance
on output measures and calculation methods for generators of electricity
and other forms of distributed energy is provided in subsection 2.4.4.

##### 2.4.1.1 Output Measures and Intensity Metrics

Many reporters already have experience reporting energy-intensity and/or
greenhouse gas-intensity data for their operations. Companies receiving
Federal and/or State funds to deploy energy-efficiency equipment or
processes likely have had to report their energy-intensity improvements
over time. Many entities participating in the Climate VISION and Climate
Leaders programs have established greenhouse gas-intensity targets.

Greenhouse gas intensity metrics, which are designed to indicate changes
in emissions that are independent of economic growth or increases in
production, use either a physical or an economic value for the
denominator (see Table 2.1). For example, the greenhouse gas emissions
intensity of steel production can be measured as emissions per ton of
steel product (physical metric), or emissions per dollar of value added
by the steelmaker (economic metric). The denominator can be an input
into the manufacturing facility when the output slate is
complicated---for example, a refiner could report emissions per barrel
of crude oil processed.

Physical measures of output are typically used for commodity industries
with homogeneous production outputs (e.g., tons of steel, aluminum, or
paper). Physical measures also include floor area (square feet or square
meters), number of employees, and units of product manufactured or
assembled.

Economic measures (e.g., "value of shipments" and "value added") are
typically used when aggregating across heterogeneous entities that do
not produce comparable products, such as in fabrication industries,
manufacturers of machinery and textiles, and food processing. These
measures may be more practical for more complex industries or firms that
produce a variety of disparate products. "Value of shipments" from the
surveyed firms is reported by the U.S. Department of Commerce's Bureau
of Economic Analysis, and "value added" is reported in the Census
Bureau's *Annual Survey of Manufacturers*.

Typically, there is greater variability in economic measures relative to
physical measures and physical measures values more accurately trace
actual trends in emissions intensity. However, heterogeneity of the
products manufactured by most industrial plants can make development of
such physical metrics challenging. There have been increasing efforts to
develop suitable physical metrics in the United States, Netherlands, and
Canada

###### Table 2.1. Greenhouse Gas Intensity Denominators for Industry and Service Companies

  -----------------------------------------------------------------------
  **Physical Measures**                  **Economic Measures**[^180]
  -------------------------------------- --------------------------------
  Weight of product or output (lb, ton,  \$ Gross output
  metric ton)                            

  Number of units of product             \$ Value of shipments

  Quantitative description of function   \$ Value added
  or service provided                    

  Units of energy sold (kWh, Btu, bbl)   \$ Revenue

  Units of input processed (bbl crude)   

  Number of employees or students        

  Floor area (ft^2^, m^2^, etc.)         
  -----------------------------------------------------------------------

Mergers and acquisitions, plant closings, varying product lines
(crossing industrial categories), and other structural changes can
obscure output trends based on both physical and economic metrics.
Specific adjustments to base values may be needed to add or subtract
business units that have been acquired or divested, or to include or
exclude stages of the production process that have been insourced or
outsourced. Those adjustments would be made if the emissions associated
with the applicable elements of the production process have been
measured separately or can be estimated.

##### 

##### 

##### 2.4.1.2 Output Measure Selection Criteria

Each reporter can select the output measure(s) most relevant for its
entity and/or subentities. DOE has already reviewed the measures used
successfully by others in the United States and abroad to track both
energy intensity and greenhouse gas intensity. Since its first request
for comments from interested parties in the summer of 2002, DOE has
received some very specific recommendations and interviewed
representatives of trade associations and manufacturing entities to
obtain a better understanding of what is practical. Based on this input,
DOE offers the following criteria to assist reporters in selecting
appropriate output measures:

-   ***Select an output measure that can work over time***. Reporters
    should revise their base period(s) only when necessary. Consistency
    in the output measure will enable the reporters and DOE to track the
    trends toward the goal of an 18-percent reduction in greenhouse gas
    emissions intensity.

-   ***Choose physical measures over economic measures as the preferred
    measure of output***. Physical measures of output or input (see
    Table 2.1) work well for most commodity industries (e.g., steel,
    cement, paper) and select service establishments (e.g., office
    building, schools). Manufacturing establishments with heterogeneous
    products (e.g., fabrication, food, textiles) may not lend themselves
    to a single physical measure even if reporting is performed for
    subentities. DOE recognizes that in such circumstances an economic
    measure may be preferred. Economic measures should be denominated in
    current dollars: EIA will convert to constant dollars using the
    Gross Domestic Product (GDP) price deflator. The GDP deflator is a
    measure of the cost of goods and services purchased by U.S.
    household, government, and industry. EIA will provide a worksheet
    for reporters to gauge the effect of such a calculation on the
    computation of reductions. Please refer to Table 2.2 for examples of
    possible output measures categorized by industrial codes of the
    North American Industry Classification System (NAICS).

-   ***Select the broadest possible physical output measure***. The
    simplest way to report is at the entity level, with a single measure
    of output that is sufficiently robust to cover all manufacturing and
    supporting operations. If that is not possible, consider reporting
    greenhouse gas emissions from subentities with appropriate physical
    metrics for the various products and other measures of performance.
    If establishing intensity metrics based on physical measures of the
    output of subentities is not feasible, consider reporting greenhouse
    gas emissions from subentities with appropriate economic metrics for
    different products. Aim for the broadest coverage feasible.

-   ***Apply the one output measure: one subentity rule***. In those
    cases where subentities are necessary, each subentity should have a
    unique measure of physical output. Subentities with identical
    outputs should be grouped together as a single subentity, unless
    they have different Base Periods.

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-   ***Use output measures that have a track record***. For example, use
    metrics that have already been reported to a trade group or other
    data-gathering organizations, such as the Census Bureau. Explaining
    and justifying the selection of an output measure is easier if the
    measure has been used previously by the reporter or other entities
    with the same types of output.

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-   ***Set limits on changing the metric***. Changes in major
    manufacturing processes or product slate, mergers, acquisitions, and
    divestitures, may necessitate the use of an alternative metric. In
    select cases, changing the base periods may be sufficient and the
    instructions in subsection 2.3.3.2 can be followed. In other
    situations the metric used historically may no longer be relevant.

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-   ***Document all output measures.*** All entities must (a) provide a
    rationale for the selection of each output measure, (b) define and
    describe each output metric, including calculations and factors
    used, (c) provide a few years of trend data for any new intensity
    metric developed, and (d) describe the scope of activities covered
    by the chosen output measure.

##### 2.4.1.3 Calculation Approach

For changes in intensity, the calculation is straightforward for an
entity or subentity: calculate the change in greenhouse gas (GHG)
emissions (in tons) by subtracting the base period greenhouse gas
intensity from the reporting year greenhouse gas intensity and multiply
the change by output in the reporting year. This approach is represented
by the following equation.

**GHG Emission Reduction = \[(E~B~/O~B~) - (E~R~/O~R~)\] \* O~R~**

**Where:**

> **E = greenhouse gas emissions (in tons)**
>
> **O = output** **(in selected measure)**
>
> **(E/O) = GHG intensity**
>
> **R = Reporting Year**
>
> **B = Base Period(s)**

It is important to note when using this formula, a positive change (Base
Period is higher than Reporting Year) is an emission reduction in
greenhouse gas intensity; a negative change (Base Period in lower than
Reporting Year) is an increase in greenhouse gas emissions. If
applicable, the reporter sums the changes in greenhouse gas emissions
for each of the subentities to calculate total net reductions. The total
net change in greenhouse gas emissions will be the final number reported
to EIA.

##### 2.4.1.4 Partial List of Physical Output Measures Currently in Use

##### 

Table 2.2 provides a list of suggested measures of physical output
currently in use by NAICS codes.

###### Table 2.2. Partial List of Physical Output Measures Currently in Use by NAICS Codes

  ----------------------------------------------------------------------------
  **NAICS**   **NAICS Description** **Physical Units**
  ----------- --------------------- ------------------------------------------
  111         Crop Production       metric tons

  113         Forestry and Logging  acres

  212         Mining (except Oil    metric tons
              and Gas)              

  221         Utilities             kilowatt-hours, revenues (\$)

  311         Food Manufacturing    short tons, metric tons, lbs, kg, sacks
                                    (flour), bushels (wheat), kilolitres

  313         Textile Mills         1,000 lbs, million hours (spindle), bales
                                    (cotton), square yards (fabrics), lbs (tie
                                    cord)

  314         Textile Product Mills square yards, dozens

  321         Wood Product          billion board feet, cubic meters
              Manufacturing         

  322         Paper Manufacturing   short tons, metric tons

  323         Printing and Related  square meter
              Support Activities    

  324         Petroleum and Coal    million barrels per day (crude throughput)
              Products              
              Manufacturing         

  325         Chemical              short tons, metric ton, gallons, cu ft
              Manufacturing         

  326         Plastics and Rubber   metric tons
              Products              
              Manufacturing         

  327         Nonmetallic Mineral   billion square feet, short tons, metric
              Product Manufacturing tons, tones (clinker), kilograms, million
                                    dozen (tumblers, cookware, stemware),
                                    million pieces (tableware), 1,000 bricks,
                                    square meters (wall tile)

  331         Primary Metal         million tons by metal smelted, 1,000 short
              Manufacturing         tons (steel in process, finished steel),
                                    1,000 metric tons by grade (carbon, alloy,
                                    stainless) & furnace type

  332         Fabricated Metal      million tons by metal, 1,000 units by type
              Product Manufacturing 

  333         Machinery             units by type ,units by fuel (gas, diesel,
              Manufacturing         NG, LPG)

  334         Computer and          units by type, square meters of silicon
              Electronic Product    
              Manufacturing         

  335         Electrical Equipment, units by type, 1,000 lbs gross (by type of
              Appliance, and        material), 1,000 units (if product type
              Component             does not change substantially over time)
              Manufacturing         

  336         Transportation        units by type (cars, trucks), vehicle
              Equipment             
              Manufacturing         

  337         Furniture and Related units by type
              Product Manufacturing 

  339         Miscellaneous         units by type
              Manufacturing         

  442         Furniture and Home    units by type
              Furnishings Stores    

  486         Pipeline              barrels of throughput 
              Transportation        

  51          Information           employees, square feet of building space

  523         Securities, Commodity square feet of building space
              Contracts, and Other  
              Financial Investments 
              and Related           
              Activities            

  531         Real Estate           square feet of building space, by category
                                    of commercial building; number of
                                    apartments or residential units

  541         Professional,         square feet of building space, employees
              Scientific, and       
              Technical Services    

  562         Waste Management and  tons waste processed 
              Remediation Services  

  611         Educational Services  student enrollment, faculty employment

  62          Health Care and       beds, square feet 
              Social Assistance     

  812         Personal and Laundry  lb laundry cleaned, employees
              Services              

  813         Religious, Civic,     square feet of building space, by category
              Professional, and     of commercial building
              Similar Organizations 

  814         Private Households    household, person

  921         Executive,            employees, square feet of building space,
              Legislative, and      by category of commercial building.
              Other General         
              Government Support    

  928         National Security and sq. ft., employees
              International Affairs 
  ----------------------------------------------------------------------------

#### 2.4.2. Changes in Absolute Emissions

In general, the formula for determining emission reductions for the
entire entity or for each sub-entity using the absolute-emissions method
is:

**Change in GHG Emissions = AE~B~ - AE~R~**

**Where:**

> **AE = absolute greenhouse gas emissions (in metric tons)**
>
> **R = Reporting Year**
>
> **B = Base Period**

The reporter then sums the changes in greenhouse gas emissions for each
of the subentities. The total net change in greenhouse gas emissions
will be the final number reported to DOE.

This calculation method may be used by any entity to calculate and
report emission reductions. However, entities that intend to register
emission reductions may use this method only if the entity can
demonstrate that the output associated with the absolute emissions has
not declined. To do this, reporters must identify a physical or economic
measure that can serve as a sufficiently credible proxy for output and
changes in output. Some acceptable output measures are described above
in subsection 2.4.1.2.

Entities or sub-entities that experience year-to-year declines in output
and intend to register reductions may continue to use this method as
long as their current output is at least equal to their Base Period. An
entity may not use this method to qualify for registered reductions for
any year that its overall output is lower than it was in its Base
Period. However, an entity that experiences one or more years of lower
output may continue to report, and may use this method of calculating
emission reductions to qualify for registered reductions in the future,
if its output again equals or surpasses its Base-Period output.

Another option for an entity that begins to experience sustained periods
of declining output relative to its Base Period is to calculate its
emission reductions using one or more subentities. Changes in the
emissions of those subentities with declining output might be assessed
using emissions-intensity methods, while subentities with stable or
increasing output could continue to be assessed using absolute-emissions
methods.

The value of the Base-Period emissions used to calculate changes in
absolute emissions must be adjusted to reflect boundary changes,
including the acquisition and divestiture of significant emission
sources and the outsourcing or insourcing of significant
emission-producing activities. Base-Period emissions must represent all
sources of emissions included in the entity's emissions inventory for
the reporting year, and exclude sources or activities that have been
divested or outsourced (i.e., sources or activities that have been
transferred to another entity and are still producing emissions).

Base-Period emissions may include emissions from sources that are no
longer emitting in the Reporting Year. No adjustment may be made,
however, to Base-Period emissions resulting from the addition of new
emission sources, unless the reporter can demonstrate that the addition
of this source represents the insourcing or acquisition of an activity
previously conducted by another entity in the Base Period (rather than
establishment of a new activity or expansion of an existing activity
some time after the chosen Base Period---also referred to as organic
growth).

#### 2.4.3. Changes in Carbon Storage

Entities reporting under 1605(b) are eligible to register reductions
associated with increases in carbon stocks. The next subsection
describes the procedures that should be followed to calculate annual
volumes of reductions associated with increases in carbon stocks.
Entities can calculate reductions from:

-   Increases in terrestrial carbon stocks (forest, agriculture,
    rangelands).

-   Increases in carbon storage in wood products.

-   Preservation of existing terrestrial carbon stocks.

Geologic carbon sequestration requires an action-specific method and is
discussed in subsection 2.4.5.6.5.

##### 2.4.3.1 Calculating Reductions from Increases in Terrestrial Carbon Stocks

Entities with carbon emissions from terrestrial carbon stocks that
exceed *de minimis* criteria of the 1605(b) Program must report
estimates of annual carbon fluxes consistent with the General
Guidelines. Absolute increases in terrestrial carbon stocks can
contribute to an entity\'s registered greenhouse gas reductions within
the 1605(b) Program. Terrestrial carbon pools that can be enhanced
include: forest trees, forest understory, forest dead and downed wood
(onsite), forest floor, forest soils, agricultural soils, range and
grazing land soils, and wood products. Under this provision, entities
are required to use inventory methodologies described in Chapter 1,
Parts H and I to estimate total carbon stocks and/or fluxes from carbon
pools on lands being reported, and methods found in this section for
calculating reductions.

Changes in terrestrial carbon stocks can either be positive (carbon
sequestration) or negative (carbon emissions). Chapter 1, Parts H and I
provide two options for calculating the changes in carbon stocks.
Entities can calculate annual carbon fluxes directly as the quantity of
carbon sequestered or emitted. Otherwise, entities can calculate annual
carbon fluxes by assessing the total carbon stocks at the beginning and
end of a period.

In cases where carbon-stock estimates are used to generate the
carbon-flux estimates, entities should report both the carbon stock and
flux values to enhance transparency. In many cases, entities will
develop estimates of carbon stocks and fluxes for base and reporting
years from periodic inventories or estimates, made at 5-year increments.
While this is acceptable, entities are required to report this
information annually and use the inventory guidelines described in
Chapter 1 to generate an annual estimate. In no case should an entity
use a projection to estimate carbon-stock values for the base period.

**2.4.3.1.1 Purchase or Sale of Land**

Entities' landholdings may change over time. If lands being reported
under 1605(b) are sold or divested, the entity selling the land must
reduce its carbon-stock estimates for the reporting year and the base
period to reflect that the land is no longer under the entity's control.
Entities purchasing lands that are already being reported under 1605(b)
may continue to report on those lands, and can estimate reductions based
on the fluxes that occur in the first year of ownership or on the change
of carbon stocks from the year prior to purchase, based on the value
reported by the entity that sold the land.

Entities choosing to use a base period that ends after 2002 that owned
the affected land during 2002 must provide an estimate of the change in
carbon stocks that occurred from the end of 2002 to the end of the
chosen Base Period. Entities that purchased land after 2002 that has not
been reported previously under 1605(b) should provide an estimate of the
change in carbon stocks from the year of purchase to the end of the
chosen Base Period.

**2.4.3.1.2 Carbon Emissions from Land Use in the Base Period**

In some cases, an entity's base-period inventory will indicate a decline
of carbon stocks (net carbon dioxide emissions). Emissions of carbon
dioxide from land use can result from the cultivation of organic soils,
cultivation of mineral soils, forest management practices, and land
conversion.

Cultivated organic soils include histosols, mucks, and peats that have
been drained and converted to crop or pastureland. Because carbon
dioxide emissions from organic soil cultivation can continue essentially
indefinitely (for periods of more than 100 years), entities that report
emissions of carbon dioxide from organic soil cultivation should use the
guidance for calculating changes in emissions intensity (see subsection
2.4.1) or changes in absolute emissions (see subsection 2.4.2) for
estimating registered reductions associated with carbon emissions from
this land use.

Because carbon dioxide emissions associated with most other land uses
occur for a finite period (from 1 to 20 years) and cease once the land
reaches a new equilibrium condition, entities reporting carbon dioxide
emissions from all land uses except organic soil cultivation should use
the methodologies for calculating increases in terrestrial carbon
stocks. Entities should use the carbon stocks at the end of the base
period as the basis for the reductions calculation.

**2.4.3.1.3 Natural Disturbances**

Entities that experience a natural disturbance such as natural fire,
pests, or extreme weather, can choose to account separately for the
emissions associated with these natural phenomena. Entities reporting
emissions from natural disturbances separately should identify the
emissions and the cause so that they can be tracked separately and noted
in summary information made available by EIA. Entities cannot report
additional reductions associated with increases in carbon storage on
lands that have undergone natural disturbances until the carbon stocks
return to pre-disturbance levels.

##### 2.4.3.2 Reductions from Increases in Carbon Stored in Wood Products

The Guidelines specify that the entity reporting changes in forest
carbon stocks also report the changes in carbon stocks that are expected
in the wood-products pool. Because harvested wood is typically
transferred between owners as the wood is harvested, processed, and
used, several entities could potentially affect the quantity and timing
of the carbon emitted from wood products. The decision to allow the
forest-carbon reporter to also report expected changes in wood-products
carbon simplifies overall reporting burdens and allows the increases in
wood-products carbon storage to be captured in the 1605(b) reporting
systems.

Carbon harvested and removed from forests will not generally flow to the
atmosphere immediately. Significant quantities of carbon harvested from
forest systems is likely to be stored for long periods in the form of
wood products or in materials deposited in landfills, and some of this
carbon is likely to permanently sequestered. Since most declines in
carbon stocks would be treated as an emission increase under the revised
guidelines, entities that are reporting changes in terrestrial carbon
stocks should also include in their reports estimates of the expected
storage of carbon in wood products. The guidelines allow two approaches
to estimate the amount of carbon stored in wood products.

The first approach is to estimate the decay of materials stored in wood
products over time so that the resulting emissions are accounted for in
the year in which they occur. This would require entities to report each
year an estimate of the decline in the carbon stored in the wood
products that were derived from the materials harvested by the entity
since the base period. The following formula would be used to estimate
the carbon stored in the wood products in a given year.

[]{.mark}

**Carbon Stored in Wood Products =**

**Σ ~(for\ base\ to\ reporting\ year)~ Volume of Carbon Harvested
~(year)~ \* % Stored in Products ~(year)~**

Because this first approach would require entities to report on all
materials harvested since the base period in each reporting year, many
entities may find it overly burdensome. Such entities could choose a
much simpler approach. This second approach would allow an entity to
register the amount of carbon expected to remain in products and
landfills after a 100-year period and to report this value in the year
that the material is harvested. This approach would mean that the
emissions likely to be produced by wood products over a 100-year period
would be accounted for in the year of harvest. The following formula
would be used to estimate the carbon stored in the wood products 100
years after harvest.

[]{.mark}

**Carbon Stored in Wood Products = Volume of Carbon Harvested \* (100
Year Residue)**

Reporting entities must identify which of these two approaches they used
and provide to EIA the data and spreadsheets or worksheets used to
calculate these values. See the Appendix to Chapter 1, Part I, sections
1.C and 1.D.

##### 2.4.3.3 Reductions from Carbon Stock Changes on Incidental Lands

Incidental lands are entity landholdings that are a minor component of
an entity's operations and are not actively managed for production of
goods and services, including: transmission, pipeline, or transportation
right of ways that are not managed for timber production; land
surrounding commercial enterprises or facilities; and land where carbon
stock changes are determined by natural factors. If the incidental lands
are not developed during the reporting period, entities have the option
to use the guidelines in Chapter 1, Parts I to estimate changes in
above- and below-ground carbon stocks on incidental lands or to assume
that carbon stocks on incidental lands are not changing. Regardless of
which option is chosen, entities must report on the area and type of
incidental lands owned. If incidental lands are converted to developed
uses, the impact of development on carbon stocks must be accounted for
in the entity inventory according to the guidance in Chapter 1, Part I,
"Forestry Emissions."

# 

**2.4.3.4  Reductions from Land Restoration and Preservation**\
\
The revised 1605(b) General Guidelines allow entities to accelerate the
registration of reductions associated with land restoration and
preservation activities. To be eligible for this provision, an entity
must restore native habitat on land and place administrative
restrictions on the land to ensure that human-caused releases of carbon
from the lands do not occur in the future. Administrative restrictions
can either be permanent conservation easements that are registered with
the County, State, or other Government entity, or deed restrictions. The
entity can register 50 percent of the carbon stock increases that are
expected over the 50 years following the activity\'s inception and the
establishment of permanent easement or deed restriction. These
carbon-stock increases should be calculated using the guidelines for
calculating increases in terrestrial carbon stocks outlined in Chapter
1, Part I.4. No additional reductions (or changes in carbon stock)
attributable to these lands may be reported or registered. However, all
inventory reporting provisions contained in Chapter 1 of these Technical
Guidelines continue to apply to these lands. 

#### 2.4.4. Avoided Emissions

As used in these Technical Guidelines, avoided emissions occur when an
energy product (including electricity, hot water, steam, and chilled
water) produced by a non- or low-emitting source is distributed to
customers that would have otherwise purchased a comparable energy
product generated by a higher-emitting source. This subsection provides
technical guidance on applying this method, which in some cases may be
used alone, as described below, but in most cases should be used in
combination with a method that provides an integrated calculation of
both Avoided Emissions and Changes in Intensity, as explained in section
2.4.6.

##### 2.4.4.1 Calculating Reductions Associated with Avoided Emissions

If the entity or subentity generating the energy had no emissions in its
chosen Base Period, emission reductions associated with the generation
and distribution of electricity, steam, heat or cooling must be
calculated using only the changes in avoided emissions method. This is
likely to be true for only those entities that distribute energy that is
generated, exclusively, by nuclear power or renewable energy (e.g., wind
farms), and those entities or sub entities that did not distribute
energy during their chosen Base Period (e.g. a new, independent
gas-fired combined cycle power plant that wasn't operational during the
Base Period). These reductions are calculated by multiplying the
quantity of incremental generation (the difference between the Reporting
Year Generation and the Base Period generation) by the difference
between an entity's Reporting Year emissions intensity (or zero, if
there are no emissions) and the appropriate Benchmark emissions value:

***Reductions ~Incremental~ = (Benchmark Intensity -- Emissions
Intensity ~Reporting\ Year~)***

***\* Incremental Generation (MWh or MMBtu)***

If a producer of electricity, steam, or hot/chilled water for export
(sale) to other entities/users had emissions during its chosen Base
Period, then it must use an integrated formula that combines the Avoided
Emissions method with the Changes in Intensity method to calculate the
emission reductions associated with any increases in the quantity of
energy they have generated for distribution (to other entities or users)
as described in section 2.4.6, below.

##### 

##### 2.4.4.2. Avoided Emissions Benchmark(s) and Indirect Emissions Conversion Factors

From time to time, EIA will calculate and publish avoided emissions
benchmarks and indirect emissions conversion factors for use in
calculating emission reductions. The benchmarks will differ from the
emissions coefficients used in the development of emission inventories,
but must be used in all calculations of emission reductions involving
either avoided emissions or indirect emission reductions. EIA may
coordinate the timing of any changes in such benchmark or emission
conversion factors with the periodic review and updating of the
guidelines by DOE pursuant to Section 300.1 (f) of the General
Guidelines.

**2.4.4.2.1. Avoided Emissions Benchmarks**

The avoided emission benchmark for electricity generation will be an
approximation of the average emissions intensity of fossil-fired
electric power generation for state-based regions in a recent year,
except that no benchmark will be higher than 0.9 metric tons of carbon
dioxide equivalent per megawatt hour of generation. The regional
benchmarks for avoided emissions will be based on the same regions as
those specified by EIA for indirect emissions for purchased electricity.
The average intensity of the fossil-fired electricity generation in the
2002 was approximately 0.9 metric tons of carbon dioxide equivalent per
megawatt hour generated (at the point of generation). National and
regional values fluctuate annually as a result of a wide range of
different factors, including the relative prices of different fuels used
in power generation and weather. Therefore, EIA may choose to calculate
an average value for two or more years. These factors are also expected
to change over time as new power plants are built and existing plants
are retired. The values will be recalculated by EIA whenever the
electric sector has undergone permanent changes that are clearly more
significant than the changes likely attributable to non-permanent annual
variations.[^181] EIA will also specify and periodically update avoided
emission benchmark values for distributed heating and cooling energy,
based on these guidelines and the best data available.

**2.4.4.2.2. Indirect Emissions Factors for Calculating Reductions**

Indirect emissions factors must be used by reporters seeking to quantify
emission reductions associated with reduced purchases of electricity,
heat, or cooling. For purchases of electricity, indirect emissions
factor(s) specified by EIA will reflect the emissions from fossil-fired
plants in the region in which the electricity demand occurred that are
necessary to deliver one megawatt hour of electricity to the point of
use. For example, based on a weighted average of 1999-2002 data, a
megawatt hour of electricity at the point of use in Florida required
emissions of 0.837[^182] metric tons of carbon dioxide equivalent to
generate. Such factors will vary annually as result of a number of
different factors, such as weather. For this reason, EIA may specify
factors that reflect a single year or a multi-year average. These
factors are also expected to change over time as new power plants are
built and existing plants are retired. The values will be recalculated
by EIA whenever the electric sector has undergone permanent changes that
are clearly more significant than the changes likely attributable to
non-permanent annual variations.

**2.4.4.2.3. Avoided Emissions Benchmarks and Indirect Emissions Factors
for Activities Outside of the United States**

To establish an avoided emissions factor, entities reporting emission
reductions achieved outside the United States should use the average
greenhouse gas emissions intensity of fossil-fired electricity
generation for the country in which the electricity was generated or
used. If available, entities should use foreign country factors
developed by EIA. Alternatively, entities may use factors published in
the most recent report of such statistics issued by the International
Energy Agency (IEA).[^183] If such statistics are not available from the
IEA, they should be obtained by the official government statistics for
that country. If no official government statistics exist, the U.S.
benchmark value should be used. For thermal energy, entities should use
the values specified for the United States, unless the reporter can
determine the appropriate values for each country for which such values
are required, using the same basic assumptions specified above. Indirect
emissions factors should be derived using the same methodology, but
should also include an adjustment for the typical losses incurred in the
transmission and distribution of energy within the borders of the
country for which activities are being reported.

#### 2.4.5. Action-Specific Calculation Methods

There are certain circumstances, defined by DOE, in which
action-specific calculation methods presented in this subsection may be
used to estimate emission reductions. There are a number of special
circumstances or actions that result in emission reductions that cannot
or should not be quantified using any of the measurement or other
estimation methods provided for in these guidelines. For example, there
may not be historic data readily available on a relevant output metric
that allows the reporter to capture the effect of a specific action on
emissions intensity. At the same time, overall output associated with
the specific action may be declining, precluding the calculation of
emission reductions based on changes in absolute-emissions levels. The
specific action also may not result in an avoided emission from
electricity, steam, heat, or cooling generation, and may not yield a
change in carbon-storage levels. In addition, there are many situations
for which the special methods defined in this section were specifically
designed.

It is likely that most specific actions can be defined as distinct
subentities and associated emission reductions can be calculated using
methods described in subsections 2.4.1 through 2.4.4. If an entity is
intent on registering emission reductions, it must, wherever feasible,
use one of these methods to calculate its emission reductions. However,
for the small set of specific actions in which emission reductions
cannot be quantified using any of the other methods identified, entities
intending to register emission reductions should use the action-specific
calculation methods identified in this section. Entities not intending
to register reductions may use action-specific calculation methods
whenever they are applicable.

Reductions calculated using action-specific methods should be consistent
with all principles applicable to the other four calculation methods
identified under these Technical Guidelines. Those principles include:

-   The reporter should clearly identify the name and nature of the
    action undertaken to reduce emissions.

-   The reporter must clearly describe the activities and emission
    sources affected by the action.

-   Emissions and emission reductions affected by this action should not
    appear in any other subentity or entity-wide emission-reduction
    calculation submitted by the reporter.

-   Emission reductions reported using this calculation method may not
    be reported by any other entity on an entity-wide or subentity
    basis.

-   Base-year or base-period emission levels should be calculated for
    the year(s) prior to the entity's first reporting year.

-   Base-year or base-period emissions must be derived from actual or
    estimated emissions for the extant process or technology in the
    entity's base period.

-   Reporters should submit emissions and emission-reduction data on an
    annual basis subsequent to the first reporting year. If a reporter
    fails to report on a specific action in a subsequent year, future
    submissions must include data for all intervening years.

##### 2.4.5.1 Documenting Specific Actions

In addition to the information required for any subentity, the following
general information should be reported:

-   Action-specific name -- Ensure that the name of each action-specific
    subentity clearly identifies the specific action being reported. It
    should be distinct from the entity name or the name of any other
    subentity. If the action is repeated at several facilities with
    differing base-year technologies or processes, each distinct action
    must be reported as a separate subentity and the name should
    indicate both the specific action and the facility covered.

-   Date action was initiated -- Provide the month and year that the
    specific action was initiated.

-   Reason(s) for specific action -- Indicate whether the specific
    action was undertaken voluntarily, or as part of a Federal, State,
    or local requirement.

-   Description of specific action -- Provide a detailed description of
    the specific action taken. For example, if an entity has installed
    more efficient motors in a manufacturing plant, the report should
    indicate the efficiency of the motors displaced and the efficiency
    of the replacement motors.

-   Activities affected -- Reporters should indicate the activities
    affected by the specific action used to reduce emissions. To the
    extent possible, those activities should be discrete and definable
    by technology, equipment, process, or output. Examples might include
    the following: lighting; heating, ventilation, and air conditioning;
    motors; transformers; vehicles; waste management; coal mining; and
    livestock management. Reporters should provide as much specificity
    as possible on the exact nature of the activities.

-   Equipment affected -- Reporters should indicate the number of pieces
    of equipment affected by the specific action. For example, reporters
    should provide the number of vehicles, transformers, or lights
    affected by the specific action. If the number of pieces of
    equipment changes, the reporter may continue to report using the
    same subentity name, base period(s), and base-value emissions, but
    must calculate any reported reductions based on the equipment
    actually in use during the reporting year.

-   Emissions source affected -- Reporters should identify the source of
    emissions associated with the specific action taken. In many cases
    the source of emissions will not arise directly from the equipment
    affected by the action, but may occur elsewhere, such as from the
    entity's boiler or the entity's electricity consumption at a
    specific plant or facility. If the emission sources associated with
    the specific action change (e.g., power is purchased from a new
    dedicated facility or the boiler has been upgraded), base-year or
    base-period emissions should be restated to reflect the emissions
    intensity of the new emissions source.

##### 2.4.5.2 Calculation of Action-Specific Emission Reductions

**2.4.5.2.1 Action-Specific Base Periods**

Unless otherwise specified below, the base period from which base-value
emissions and other performance characteristics are derived should be
immediately prior to the year of the identified action.

**2.4.5.2.2 Action-Specific Base Values**

Action-specific base values must be in one of two forms:

-   Total emissions, total captured emissions (e.g., methane recovery
    from landfills or coal seams), or another fixed quantity that is
    directly translatable into emissions; or

-   Derived emissions per unit of output or service (e.g.,
    kilowatt-hours \[kWh\] per square foot of lighted space) based on
    technology or process use, or an intensity metric that is directly
    translatable into an emissions-intensity value.

The emissions and output quantities must be derived from the actual or
estimated emissions of the process or technology extant in the entity's
base year or base period. If measured data on actual emissions and
output are not available, estimates based on the tested performance of
the type of process or technology employed during the base year or base
period may be used. For example, if the entity used incandescent
lighting during the base year or base period, emissions may be estimated
by multiplying the total rated wattage of the lights affected by the
action by the estimated hours of operation of those lights. The
resulting estimate of electricity (kWh) used would then be converted to
emissions using the default emissions factor supplied by EIA, in
accordance with these guidelines.

**2.4.5.2.3 Calculating Action-Specific Reductions**

Action-specific emission reductions are derived by comparing the
established base value to the comparable values for the reporting year.

If the base value is in the form of absolute emissions, emissions
captured or other fixed quantity, reductions are calculated by comparing
the base value to the comparable quantity for the reporting year,
derived using the compatible measurement or estimation techniques. For
example, emission reductions associated with landfill gas recovery are
determined by comparing the amount of gas recovered in the base period
to the amount of gas recovered in the reporting year for the same group
of landfill operations.

If the base value is in the form of emissions intensity (or energy
efficiency), reductions are calculated by comparing the base-value rate
of emissions intensity to the comparable rate for the reporting year,
then multiplying by the output value for the reporting year. For
example, the efficiency of a lighting system before and after a
technology change could be determined and the difference between those
two rates calculated. The change in efficiency could then be multiplied
by the hours of operation or other output measure in the reporting year
to estimate the resulting emission reduction.

##### 2.4.5.3 Documenting Data Collection, Estimation, and Calculation Methods

All reports using action-specific methods must provide a summary
description of all measurement, estimation, and calculation methods used
to determine the reported emission reductions.

##### 2.4.5.4 Comprehensive Assessment of Emissions

Reporters must perform a comprehensive assessment of the direct and
indirect effects on emissions of each specific action in each year for
which reductions are being calculated. This includes the extent to which
the specific action may increase emissions of alternative gases, or may
increase emissions from other sources within the entity's control that
are not directly affected by the specific action. Reporters should also
note potential increases in emissions that will occur outside the
entity's boundary as a result of the specific action.

##### 2.4.5.5 Continuous Reporting

As in the application of all other calculation methods, entities
registering reductions from specific actions must continue to report
annually on each such action. If a gap in annual reporting occurs, the
entity must file reports for the missing year(s) prior to registering
any further emission reductions.

##### 2.4.5.6 Specific Guidance for Certain Categories of Actions

DOE recognizes that there are a number of specific actions for which
developing an estimate of base-period(s) emissions based on extant
technology or process and base-period activity levels is not practical.
For those specific actions we have provided the following guidance on
establishing base-period(s) emissions and calculating reductions.

**2.4.5.6.1 Coalmine Methane Gas Recovery**

Coalmine degasification may take several forms, including standard
ventilation techniques, horizontal boreholes, gob wells, and pre-mining
degasification. For standard ventilation techniques, horizontal
boreholes, and gob wells, the DOE assumes that absent efforts for
recovery, all methane flows would have been emitted to the atmosphere in
the year they are recorded. Thus, for purposes of calculating
action-specific reductions for the capture of methane emitted from
active mines, base-period recovery, rather than base-period emissions,
should be calculated. Total annual flows captured in the base period
should be recorded and the average of the annual flows assigned as the
base value. If no flows were captured in the base period, zero should be
used as the base-value quantity. Average gas recovery in the base period
should be subtracted from gas recovery in the reporting year to estimate
methane reductions.

After capture, the disposition of the methane needs to be considered. If
the captured methane was flared, then the increase in carbon dioxide
emissions should be reported. If the methane was used to generate
electricity, the carbon dioxide emissions associated with that
generation should be compared to the benchmark provided in subsection
2.4.4.2.1, "Avoided Emission Benchmarks," above, to estimate the net
effect on carbon dioxide emissions. If the captured gas is sold to a
pipeline company or for direct use as a fuel, the reporter should assume
that any changes in emissions will be captured by the consumer of the
methane and that there will be no net change in the reporter's emissions
as a result of this specific action. This calculation should be
completed for the current year and the result compared to the average
result of the same calculation for the years included in the base period
to determine net carbon dioxide reductions from the disposition of
recovered methane. This number should be added to the estimated methane
reductions to yield the total net carbon dioxide equivalent reductions
from capturing methane from standard ventilation systems, horizontal
boreholes, and gob wells.

In the case of pre-mining degasification, DOE assumes that the methane
flows would not have been liberated from the surrounding coal seam until
the coal seam was cut through. Any reductions in methane emissions
associated with pre-mining gasification should thus be estimated only
for the year that the mine was cut through. Once a coal seam that
underwent pre-mining degasification has been cut through, the methane
captured may be added to the entity's recovery numbers. Similar to
standard ventilation techniques, horizontal boreholes, and gob wells,
reductions of methane from pre-mining degasification should be
calculated by comparing total recovery in the current year to total
recovery in the base period. Because sales of electricity generated from
recovered methane, direct sales of methane, or methane flaring occur
prior to and independent of coal mining, however, changes in carbon
dioxide emissions associated with the disposition of recovered methane
may be calculated using the avoided-emission techniques outlined in the
paragraph above and aggregated with methane reductions achieved in the
year that the coal seam is cut through.

DOE requires the following documentation to register emission reductions
from coalmine degasification:

-   The name and location of the coal mine or mines affected.

-   The month and year in which the coal seam was cut through.

-   Estimated quantity of emissions from ventilation systems and any gas
    captured from degasification systems that has been vented.

-   The method of degasification (e.g., ventilation techniques,
    horizontal boreholes, gob wells, or pre-mining degasification).

-   The current method of disposition for the recovered gas (flaring,
    sale for energy recovery).

-   The volume of gas recovered in each year of the base period.

-   The heat content or percent methane of the gas recovered in each
    year of the base period.

-   The volume of gas recovered in the reporting year.

-   The heat content or percent methane of the gas recovered in the
    current year.

**2.4.5.6.2 Landfill Methane Recovery**

Landfill gas recovered and combusted through flaring or for conversion
to energy represents a reduction in methane emissions. Gas vented should
be reported as an emission in entity or subentity inventories. For
purposes of calculating action-specific reductions from the capture and
combustion of methane emitted from landfills, base-period gas recovery
(reductions), rather than base-period emissions, should be calculated.
The average of total annual flows captured and flared or sold for energy
in each year of the base period should be reported as the base value. If
no gas was captured and flared, used to generate electricity or sold for
direct use in the base period, zero should be used as the base-value
quantity. Average annual gas recovery in the base period should be
subtracted from gas recovery in the reporting year to estimate methane
reductions.

After capture, the disposition of the methane needs to be considered. If
the captured methane was flared, then the increase in carbon dioxide
emissions is biogenic and need not be reported. If the methane was used
to generate electricity, the carbon dioxide emissions associated with
that generation are biogenic, assumed to be zero for reporting purposes
and the carbon dioxide reduction will be equal to the benchmark provided
in subsection 2.4.4.2.1 multiplied by the amount of electricity
generated. If the recovered methane was added to a natural gas supply
network, this methane will displace natural gas consumption by end
users. The entity supplying the methane to the natural gas supply
network may report reductions of carbon dioxide emissions associated
with the displaced natural gas consumption. If the recovered methane was
sold directly to an end user for use as a fuel, any changes in emissions
will be captured by the consumer of the methane and there will be no net
effect of emissions reported for this specific action. This calculation
should be completed for the current year and the result compared to the
average result of the same calculation for the years included in the
base period to determine net carbon dioxide reductions from the
disposition of recovered methane. This number should be added to the
estimated methane reductions to yield the total net carbon dioxide
equivalent reductions.

DOE requires the following documentation to register emission reductions
from landfill gas recovery:

-   Name and location of the landfill or landfills affected.

-   Year of opening and closure (if applicable) for the landfill(s)
    affected.

-   Estimated volume of waste in place for the landfill(s) affected.

-   Measured or modeled quantity of emissions from the landfill(s) in
    the base year.

-   Measured or modeled quantity of emissions from the landfill(s) in
    the current year.

-   Year of installation of the gas recovery system.

-   The volume of gas recovered in the reporting year.

-   The heat content or percent methane of the gas recovered in the
    current year.

-   The current method of disposition for the recovered gas (flaring,
    electricity generation, sale to the natural gas supply network, or
    direct use)

-   The Btus of gas used to generate electricity or sold to the natural
    gas supply network or for direct use.

-   The volume of gas recovered in each year of the base period.

-   The heat content or percent methane of the gas recovered in each
    year of the base period.

-   The method of disposition for the recovered gas (flaring,
    electricity generation, sale to the natural gas supply network, or
    direct use) in each year of the base period

-   The Btus of gas used to generate electricity, sold to the natural
    gas supply network, or used directly in each year of the base
    period.

**2.4.5.6.3 Capture of Methane from Anaerobic Digestion at Wastewater
Treatment Facilities**

When wastewater is treated under anaerobic conditions, the decomposition
of its organic portion yields methane. Like methane generated from waste
at landfills, the methane generated from wastewater treatment may be
captured and either flared or used as an energy resource. Because
captured methane has value as an energy resource, operators may use an
anaerobic digester to treat the wastewater and maximize methane
generation.

For purposes of calculating action-specific reductions from the capture
and combustion of methane emitted from waste treatment facilities,
base-period gas recovery (reductions), rather than base-period
emissions, should be calculated. Average total annual flows captured and
flared or sold for energy in the base period should be reported as the
base value. If wastewater was treated aerobically during the base
period, no reductions of methane may be reported, though entities may
calculate changes in indirect emissions from electricity generated and
used on-site or avoided emissions from the sale of electricity generated
from recovered methane in accord with the Section 2.4.4 of these
Technical Guidelines. If wastewater was treated anaerobically and no gas
was captured and flared or sold for energy recovery during the base
period, zero should be used as the base-value quantity. Gas recovered in
the base period should be subtracted from gas recovery in the reporting
year to estimate methane reductions. If wastewater was treated
aerobically during the base period, the introduction of an anaerobic
digester may increase nitrous oxide emissions and these increases should
be quantified.

After capture, the disposition of the methane needs to be considered. If
the captured methane was flared, then the increase in carbon dioxide
emissions is biogenic and need not be reported. If the methane was used
to generate electricity, the carbon dioxide emissions associated with
that generation are biogenic, assumed to be zero for reporting purposes
and the carbon dioxide reduction will be equal to the benchmark provided
in subsection 2.4.4.2.1 multiplied by the amount of electricity
generated. If the recovered methane was added to a natural gas supply
network, this methane will displace natural gas consumption by end
users. The entity supplying the methane to the natural gas supply
network may report reductions of carbon dioxide emissions associated
with the displaced natural gas consumption . If the recovered methane
was sold directly to an end user for use as a fuel, any changes in
emissions will be captured by the consumer of the methane and there will
be no net effect of emissions reported for this specific action. This
calculation should be completed for the current year and the result
compared to the average result of the same calculation for the years
included in the base period to determine net carbon dioxide reductions
from the disposition of recovered methane. This number should be added
to the estimated methane reductions to yield the total net carbon
dioxide equivalent reductions.

DOE requires the following documentation to register emission reductions
from wastewater treatment facilities:

-   Name and location of the wastewater treatment facility(ies)
    affected.

-   Measured or modeled quantity of emissions from the wastewater
    treatment facility in the each year of the base period.

-   Measured or modeled quantity of emissions from the wastewater
    treatment facility in the current year.

-   The volume of gas recovered in the reporting year.

-   The current method of disposition for the recovered gas (flaring,
    electricity generation, sale to the natural gas supply network, or
    direct use).

-   The Btus of gas used to generate electricity, sold to the natural
    gas supply network, or used directly.

-   The volume of gas recovered in each year of the base period.

-   The method of disposition for the recovered gas (flaring,
    electricity generation, sale to the natural gas supply network, or
    direct use) in each year of the base period.

-   The Btus of gas used to generate electricity, sold to the natural
    gas supply network, or used directly in each year of the base
    period.

**2.4.5.6.4 Capture of Methane from Anaerobic Digestion of Animal
Waste**

Based on a technical review of the guidelines, DOE determined that the
emission reductions resulting from the capture of methane from the
anaerobic digestion of animal waste may be calculated based on changes
in the emissions intensity or changes in the absolute emissions
associated with animal waste from the base period to the reporting year.
Since no action-specific method is necessary to calculate these emission
reductions, the method originally included in the Technical Guidelines
in March 2006 has been deleted.

However, if the recovered methane was added to a natural gas supply
network, this methane will displace natural gas consumption by end
users. The entity supplying the methane to the natural gas supply
network may report reductions of carbon dioxide emissions associated
with the incremental amount of natural gas displaced. This reduction
must be calculated as follows:

**Emission Reduction = (M~R~** **-- M~B~) \* EF~NG~**

**Where,**

> **M~R~** **= quantity of methane supplied to natural gas supply
> network in the reporting year (MMBtu)**
>
> **M~B~** **= average quantity of methane supplied to natural gas
> supply network in the base period (MMBtu)**
>
> **EF~NG~** **= emission factor for natural gas (metric tons
> CO2/MMBtu)**[^184]

**2.4.5.6.5 Geologic Sequestration**

There are a significant number of variables that will affect calculation
of emission reductions from geologic sequestration. The following basic
principles must be applied when calculating reductions:

-   Geologic sequestration may be used to store carbon dioxide from
    naturally occurring reservoirs or from anthropogenic industrial or
    energy-combustion sources. Carbon dioxide that was produced by an
    anthropogenic process that would have otherwise led to its release
    into the atmosphere may be used in an emission reductions
    calculation. Carbon dioxide removed from natural reservoirs for the
    sole purpose of aiding enhanced oil or other energy recovery may
    only be used for registered reductions if the extracted carbon
    dioxide is treated as an emission in the entity's inventory.

-   The capture and sale of anthropogenic carbon dioxide does not, in
    itself, yield a reduction; it is only through long-term storage of
    carbon dioxide that a reduction may be generated. For the purpose of
    calculating emission reductions, all sales or other transfers of
    carbon dioxide to another entity must be treated as emissions in the
    year of the transfer. Entities that capture and sell carbon dioxide
    to a third party that permanently sequestered the carbon dioxide by
    injecting it into geologic formations may report reductions only if
    there is a written agreement with the third party.

-   Entities that purchase carbon dioxide for the purpose of injecting
    it into geologic formations must subtract from the final amount
    injected into the storage any difference between the volume of gas
    purchased and the amount sequestered in a geologic formation. Any
    difference between volume of gas purchased and amount sequestered
    should be included in the reporter's emission inventory. Entities
    may only register net increases in the volume of gas being
    sequestered, and may not include any carbon dioxide that has been
    extracted from the storage site for recycling in the same or other
    storage reservoirs..

-   Captured carbon dioxide that is injected into a suitable geologic
    formation for permanent storage may be considered sequestered once
    it has been stored in a sealed geologic reservoir and any fugitive
    emissions during the injection process have been subtracted; that
    is, the amount of sequestration is equal to the quantity of carbon
    dioxide injected less emissions leaked during the storage process.
    Potential source of leakage include: 1) any carbon dioxide dissolved
    or entrained in the water and oil produced from an enhanced oil
    recovery project and the resulting emissions, and 2) any carbon
    dioxide leaked from the injection wells during the storage process
    before the wells have been permanently sealed. The reporter must
    monitor any of these emission sources, for example, by using
    applicable Federal or state monitoring plans.

-   Captured carbon dioxide used for enhanced oil recovery is either
    stored in the subsurface reservoir or is returned to the surface via
    producing wells. Carbon dioxide returned to the surface is then
    recycled and reinjected. Leaks and venting can occur during the
    recycling process and needs to be monitored. If this recycling
    process is stopped (e.g., injection is terminated) before production
    is terminated, the idle injection wells pose a potential risk of
    releases of sequestered carbon dioxide unless they are sealed to
    avoid such releases. The reporter must seal, or plan to seal, the
    injection wells at the completion of the project to claim
    reductions. Operators of enhanced oil recovery sites that will not
    be sealed cannot claim reductions for any carbon dioxide injected.

-   Even if the wells are sealed it is possible that some amount of
    carbon dioxide will escape to the atmosphere in the future.
    Long-term carbon dioxide seepage from the injection wells and the
    storage site is also possible in the case of storage projects
    created specifically with the purpose of isolating carbon dioxide
    from the atmosphere. To register reductions, the reporter must
    determine the amount of carbon dioxide leaked back to the atmosphere
    using one of the following two monitoring options:

    -   Actively monitor and maintain the geologic formation used,
        treating carbon dioxide losses from the storage reservoir as
        emissions in the year in which they occur. These emissions are
        the responsibility of the same entity that claims the rights to
        the reductions achieved through the geologic sequestration
        activity. Applicable monitoring methods are described in Section
        1.G.7. The reporter may use any of the described monitoring
        methods that are rated "A" or "B."

    -   Apply a monitoring plan already approved by a relevant Federal
        or state regulatory agency for the purpose of tracking carbon
        dioxide seepage/leakage.

Like coal mine degasification and landfill methane recovery, reductions
should be calculated by comparing current-year sequestration to
sequestration levels in the base period. Reductions are equal to the net
change in sequestration levels.

DOE requires the following documentation to register emission reductions
from geologic sequestration:

-   Name and location of the source of the carbon dioxide.

-   Method of disposition for the carbon dioxide (e.g., long-term
    geologic storage or enhanced oil recovery).

-   Name and location of the geologic formation or other sink used to
    sequester the carbon dioxide.

-   Year of capture and permanent sequestration.

-   Volume of carbon dioxide captured or transferred to the entity.

-   Volume of carbon dioxide permanently sequestered less leakage during
    the storage process.

-   The method used to estimate net sequestration (e.g., Federal/state
    or new life-cycle analysis or active monitoring approach).

-   Estimated volume permanently sequestered in the base year.

-   Estimated volume permanently sequestered in the current reporting
    year.

**2.4.5.6.6 Transmission and Distribution Improvements**

The transmission and distribution of electricity does not in itself
generate emissions. Rather, inefficiencies in the transmission and
distribution (T&D) system result in "losses" between the amount of
electricity generated and the amount delivered to an end user, requiring
that incremental electricity (an amount equal to the losses) be
generated to meet the end-user's demand. T&D system operators can reduce
these losses by making physical improvements to the system or
implementing operational changes. For purposes of calculating emission
reductions from transmission and distribution improvements (operational
or physical), base-year emissions are equal to the system-wide volume of
line losses multiplied by a factor for emissions from electricity
generation.

The reporting entity, whether a utility, independent transmission
company, regional transmission organization (RTO) or other company or
institution, should exercise sufficient financial or other control over
the covered transmission and distribution system to include this system
within their entity's organizational boundary. A claim of loss reduction
might be made by 1) an regional transmission organization (RTO) based on
improvements in dispatch or system operations; 2) an independent
transmission company -- which may be part of an RTO -- based on changes
in system operations or physical upgrades; 3) a control area (typically
a larger transmission owning utility) -- which may be part of an RTO and
in some cases also part of an independent transmission company -- based
on changes in dispatch, system operations, or physical upgrades; or 4) a
non-control area transmission and/or distribution owning utility --
which may be part of an RTO and in some cases the system of an
independent transmission company and will be part of a larger control
area -- based on changes in operations or physical upgrades. The
reporting entity's assessment of losses must cover all of the
transmission and distribution system included within its organization
boundary.[^185] If the entity making the filing is part of a larger
entity or is composed of smaller entities, it must coordinate its filing
with these other entities to ensure that there is no double counting.

Entities can calculate emission reductions achieved by reducing T&D loss
intensity by following the steps below (note: because of annual
variations in T&D system losses attributable to changes in weather and
loads, DOE recommends that entities calculate base period T&D loss
ratios for multi-year base periods). Reductions in T&D losses may be
reported in either kWh or kilovolt-ampere hours (kVAh). Reporters must
choose whether to measure impacts related to reductions in T&D losses in
either kWh or kVAh and consistently report all loss impacts in the
selected unit of measurement.

Step 1: Calculate T&D Loss Ratios

Calculate base period and current year T&D loss ratios using the
following equation:

**LR = (G + I~n~ -- D)/(G + I~n~)**

**Where:**

**LR = loss ratio**

**G = electricity entering T&D system from generation**

**D = amount of electricity delivered to end users**

**I~n~ = net imports of electricity (total imports less total
exports)**[^186]

If a reporter elects to report on a control area basis, the base period
and current year transmission and distribution loss ratios should be
calculated using the following equation:

**LR = (G -- (D + ANI))/(G -- ANI)**

**Where:**

**LR = loss ratio**

**G = electricity entering T&D system from generation**

**D = amount of electricity delivered to end users**[^187]

**ANI = Actual Net Interchange**[^188] **for the control area or member
control areas, from the net generation received into the system**

Step 2: Calculate Net Change in Loss Intensity

The following equation should be used to calculate the net change in
loss intensity:

**LI = (LR~B~ -- LR~C~) \* (G + I~n~)**

**Where,**

**LI = change in loss intensity**

**LR~B~ = base period loss ratio**

**LR~C~ = current year loss ratio**

**G = electricity entering T&D system from generation**

**I~n~ = net imports of electricity (total imports less total exports)**

If reporting on a control area basis, use the following equation to
calculate the change in loss intensity:

**LI = (LR~B~ -- LR~C~) \* (G -- ANI)**

**Where:**

**LI = change in loss intensity**

**LR~B~ = base period loss ratio**

**LR~C~ = current year loss ratio**

**G = electricity entering T&D system from generation**

**ANI = Annual Net Interchange for the control area or member control
areas**

Step 3: Calculate Emission Reduction

If the change in loss intensity was calculated in kWh, use the following
equation to estimate the associated emission reduction:

**R = LI \* B**

**Where:**

**R = emission reduction**

**LI = change in loss intensity**

**B = emissions benchmark provided above in subsection 2.4.4**

If the change in loss intensity was calculated in kVAh, use the
following equation to estimate the associated emission reduction:

**R = LI \* (B \* PF)**

**Where:**

**R = emission reduction**

**LI = change in loss intensity**

**B = emissions benchmark provided above in subsection 2.4.4**

**PF = system power factor for the current year**

The power factor of an alternating current electric power system is
defined as the ratio of the real power measured in Watts to the apparent
power measured in volt-amperes. If the power factor (PF) for the
entity's T&D system is known and publicly reported outside of the
1605(b) Program, it may be used in this calculation provided it does not
exceed 0.95. If the known and publicly reported system power factor
exceeds 0.95, the reporter must use a power factor of 0.95. If the
system power factor is unknown or not reported publicly, the reporter
should use a default of 0.90 in to calculate the emission reduction.

The resulting quantity is the emission reduction (or increase)
attributable to changes in transmission and distribution losses that
should be incorporated in the entity's report to DOE.

DOE requires the following documentation to register reductions from
transmission and distribution losses:

-   Total estimated number of kWh or kVAh entering the transmission and
    distribution system from generation in the base period.

-   Total estimated number of kWh or kVAh delivered from the
    transmission and distribution system to end users and, if reporting
    on a control area basis, to independent distribution companies
    within the entity's control area or member control areas in the base
    period.

-   Total estimated net exports leaving (positive number) or net imports
    entering (negative number) the transmission and distribution system
    in the base period. If an entity is reporting on a control area
    basis, the net exports or imports should be reported on the basis of
    the Actual Net Interchange for the control area or member control
    areas in the base period.

-   Total estimated number of kWh or kVAh entering the transmission and
    distribution system from generation in the current year.

-   Total estimated number of kWh or kVAh delivered from the
    transmission and distribution system to end users and, if reporting
    on a control area basis, to independent distribution companies
    within the entity's control area or member control areas in the
    current year.

-   Total estimated net exports leaving (positive number) or net imports
    entering (negative number) the reporting entity's transmission and
    distribution system in the current year. If the report is filed on a
    control area basis, the net exports or imports should be reported on
    the basis of the Actual Net Interchange for the control area or
    member control areas in the current year.

-   If reporting changes in losses in kVAh and on the basis of a known
    power factor, the calculation of the system power factor utilized
    for reporting purposes.

-   Description of specific actions taken to reduce losses from the
    transmission and distribution system (e.g., high-efficiency
    transformers, reconductoring, distribution voltage upgrade).

**2.4.5.6.7 Recycling of Fly Ash**

Fly ash from the combustion of coal can be used as a substitute for
Portland cement in certain applications, including concrete and some
cement mixtures. These applications reduce emissions associated with the
manufacture of the displaced cement.

The key step in producing Portland cement is calcination, in which
calcium carbonate (CaCO~3~) is heated in a kiln to a temperature of
approximately 1,300°C (2,400°F). This reduces the calcium carbonate to
lime (CaO) and releases carbon dioxide to the atmosphere. Lime is
combined with silica containing materials to produce and intermediate
product called clinker, which is allowed to cool. A small amount of
gypsum is added to the clinker to produce the final Portland cement
product. This process requires substantial amounts of energy, largely
for calcination, that is provided by the combustion of fossil fuels,
which results in additional emissions of carbon dioxide.

Concrete manufacturers and cement manufacturers that replace Portland
cement with fly ash are permitted to report the resulting indirect
emission reductions using this action-specific method. Other entities,
including electric generators that produce fly ash in coal-fired power
plants, may report indirect reductions resulting from the transfer of
fly ash to the entities that substitute fly ash for cement under the
offset provisions described in §300.7(d) of the General Guidelines.

The U.S. Environmental Protection Agency (EPA) has prepared a life-cycle
assessment of greenhouse gas emissions of fly ash used as a substitute
for Portland cement in concrete.[^189] DOE has used the spreadsheet
version of EPA's WAste Reduction Model (WARM)[^190] Table 2.3 compares
the emissions for producing and transporting one short ton of virgin
cement to a concrete manufacturer with the emissions for producing and
transporting one short ton of substitute fly ash.

###### Table 2.3 Emissions Associated with Manufacturing and Transporting Virgin Cement and Fly Ash (metric tons ~2~erbon equivalent/ton of product)

  -------------- -------------- ------------------ -------------- --------------
  **Material**   **Process      **Transportation   **Process      **Net
                 Energy         Emissions**        Non-Energy     Emissions**
                 Emissions**                       Emissions**    

  Virgin Cement  0.1152         0.0021             0.1223         0.2396

  Fly Ash        \-             0.0021             \-             0.0021
  -------------- -------------- ------------------ -------------- --------------

Source: U.S. Environmental Protection Agency, Background Document for
Life-cycle Greenhouse Gas Emission Factors for Fly Ash Used as a Cement
Replacement in Concrete, EPA530-R-03-016, November 7, 2003, Exhibit 8,
p. 7.

Depending on the characteristics of the fly ash and intended application
of the concrete or cement, the ratio of fly ash to displaced cement can
range from 1:1 to 1.5:1.[^191] The displaced emissions associated with
applications of fly ash that displace Portland cement in metric tons
carbon dioxide equivalent (mtCO~2~e) can be estimated using the
following equation:

**E = F \* ((0.2396/S) -- 0.0021) \* 3.667**

**Where:**

> **E = emissions displaced by substituting fly ash for Portland cement
> (mtCO~2~e)**

**F = quantity of fly ash used (short tons)**

**S = substitution ratio of fly ash to Portland cement**

Emission reduction resulting from the substitution of fly ash for
Portland cement should be calculated using the following equations:

> **BV = (E~B~/Y~B~)**
>
> **R~RY~ = E~RY~** **-** **BV**

**Where:**

**BV = base value emissions displaced by substituting fly ash for
Portland Cement** **(in metric tons CO~2~E)**

**E~B~ = sum of emissions displaced by substituting fly ash for Portland
cement in base period (in metric tons CO~2~E)**

**Y~B~ = number of years in base period**

**R~RY~ = emission reduction for substituting** **fly ash for Portland
cementused in concretear (in metric tons CO~2~E)**

**E~RY~ = emissions displaced by substituting** **fly ash for Portland
cement** **in reporting year (in metric tons CO~2~E)**

Fly ash is used in other applications that may result in the
displacement of Portland cement, including flowable fills and waste
stabilization. In future revisions of the technical guidelines, DOE may
consider permitting the reporting of reduction from such applications if
the extent to which these applications result in the displacement of
Portland cement can be reliably determined.

**2.4.5.6.8 Destruction of Chlorofluorocarbons**

Chlorofluorocarbons (CFCs) can be used as refrigerants, blowing agents,
and solvents. The production and use of these gases is being phased out
under the Montreal Protocol on Substances that Deplete the Ozone Layer,
which came into force in 1989. In addition to destroying ozone, CFCs are
also powerful greenhouse gases. However, the direct positive radiative
forcing of CFCs are offset by indirect negative radiative forcing due to
their roles in the destruction of atmospheric ozone and methane, both of
which are greenhouse gases. Because these indirect radiative forcing
effects are difficult to quantify, the IPCC has not established single
point net global warming potentials (GWPs) for these gases, although it
has estimated a range for the net GWP for three gases (CFC-11, CFC-12,
and CFC-113).[^192] Because of the uncertainty regarding their radiative
forcing effects and their regulation under the Montreal Protocol, the
parties to the Kyoto Protocol excluded CFCs from the greenhouse gases to
be controlled. However, Section 1605(b)(1) of the Energy Policy Act of
1992 explicitly directed DOE to "establish procedures for the accurate
voluntary reporting of information on...chlorofluorocarbon capture and
replacement."

Over time, the CFCs used as the working gas in refrigeration and air
conditioning systems leak to the atmosphere and must be replaced. In
some circumstances, usually requiring some equipment modifications, CFCs
can be recovered and replaced by non ozone-destroying gases, such as
hydrofluorocarbons (HFCs). Also, when the systems are retired, however,
a certain amount of working gas is retained and can be captured by scrap
merchants that process used refrigeration or air conditioning units. The
recovered CFCs can either be recycled for use in systems that still use
CFC refrigerants or destroyed. Because some portion or all of recycled
CFCs ultimately will be released to the atmosphere through leaks from
refrigeration and air-conditioning equipment, DOE is permitting the
reporting of CFC reductions only where the gas is captured and
destroyed. The entity responsible for destruction of a CFC may report,
separately, the quantity of a given gas destroyed in any calendar year
as a reduction, but such reductions must not be included in the entity's
emission inventories or net emission reduction calculations.

Owing to the uncertainty regarding their GWPs, reductions of CFCs must
be reported in units of native gas (e.g., kilograms or metric tons of
CFC-12) rather than in units of carbon dioxide equivalent (e.g.
MTCO~2~E).

**2.4.5.6.9 Demand-side management or other emission reduction
programs**

The incremental annual emission reductions that have been independently
verified to be attributable to the effects of qualifying demand-side
management (DSM) or other programs may be reported and registered as an
offset reduction, if the reporting entity has met all other requirements
for registration. To qualify, the DSM or other program must be funded by
the reporting entity and the estimated effects reported must first occur
after the entity\'s start year and must cause a reduction of the total
emissions of residential or other very small emitters (entities that
typically emit below 500 tons of carbon dioxide equivalent per year of
greenhouse gases and are therefore highly unlikely to be reporting
entities under these guidelines). Qualifying programs must provide
information or other technical assistance, financial incentives, direct
installation or investment, or other non-commercial services to very
small emitters to assist them in achieving emission reductions
recognized by these guidelines. In this context, "non-commercial" means
that the service may not charge participants fees that are sufficient to
cover the costs of the program.

The emission reductions reported should: 1) reflect only the effects of
actions that are undertaken after the entity\'s start year specifically
in response to entity-administered programs, including program
activities implemented by third parties under contract to the entity;
and 2) be calculated based on the energy (e.g., kWh of electricity,
thousand cubic feet of natural gas) effects at the customer meter or
other measures of the changes in greenhouse gas emissions or carbon
stocks of the very small emitters affected. The reduction estimates must
exclude, to the extent possible, energy or other emission effects that
are not attributable to the identified program activities. Non-program
related effects must be excluded, including changes in energy use or
emissions attributable to: 1) free riders (i.e., program participants
that would have adopted program-recommended actions even without the
program); 2) government-mandated energy-efficiency standards that
legislate improvements in building and appliance energy usage; 3)
natural operations of the marketplace (e.g., reductions in customer
energy usage due to higher prices or reductions achieved by
non-participants that were not attributable to the effects of the
program); and 4) weather and business-cycle fluctuations. Power supply
cooperatives, municipal joint action agencies, and Federal Power
Marketing Administrations must coordinate the reporting of DSM
information with their power purchasing utilities to avoid double
counting the effects of DSM programs.

Estimates of the annual energy usage reductions attributable to
qualified DSM or other programs must be based on program evaluations
that are capable of reliably distinguishing between program effects and
non-program-related effects, and capable of estimating how
program-related effects are likely to diminish over time. Acceptable
program evaluations may require statistically valid surveys or energy
use metering of program participants and non-participants. Entity
reports must include a summary description of the DSM efficiency or
other program, the very small emitters that are the primary target of
the program, and the program evaluation methodology.

Program evaluations must be performed and/or certified by an independent
and qualified third party verifier. An independent third-party may not
be owned in whole or part by the reporting entity, nor may it provide
any ongoing operational or support services to the entity, except
services consistent with independent financial accounting or independent
certification of compliance with government or private standards. To be
qualified, the third-party must have experience in conducting or
assessing statistically-valid program impact evaluations recognized by
government agencies. Responsible government regulatory agencies are
considered to be both independent and qualified third party verifiers.
The independent third party and its qualifications must be identified in
the entity's report and the third party must certify that the estimated
annual energy usage or emission reductions were estimated in accordance
with these guidelines. Estimated annual energy usage reductions should
be converted to greenhouse gas emissions using the appropriate end-use
emissions factors, specified elsewhere in these guidelines.

#### 2.4.6 Estimating Reductions Associated with Energy Exports 

Entities or subentities that produce electricity, steam, or hot/chilled
water for export (sale) to other entities (and have emissions in the
Base Period) must calculate emission reductions by using a formula that
takes in account changes in both emission intensity and avoided
emissions simultaneously.[^193] This section describes the integrated
(or combined) methods that these entities must use.

Avoided emissions occur when an energy product, including electricity,
hot water, steam, and cooling, produced by a non- or low-emitting source
is sold (exported) to a customer that would have otherwise purchased a
comparable energy product generated by a higher-emitting source.
Producers of electricity, steam, and hot or chilled water must use this
method coupled with the Changes in Emissions Intensity method (see
subsection 2.4.1) to calculate the emission reductions associated with
any increases in the quantity of energy they have generated for
distribution to other entities or users, as described below.

##### 2.4.6.1. Estimating Reductions from Energy Generation and Distribution

Energy generators, including electricity generators and thermal
generators of steam, heating, and cooling, that sell or distribute all
or some portion of the energy they generate are potentially eligible for
reporting emission reductions. The methods described below should be
used only to estimate emission reductions associated with electricity,
heat or cooling that were exported outside of an entity's boundaries.
Emissions associated with power that was generated and used within an
entity's (or subentity's) boundaries, including energy from small
electricity generators or boilers, should be factored into the entity's
(or subentity's) estimate of the emissions intensity of its product
output for the reporting year. In contrast, emissions associated with
energy that was sold or otherwise exported outside of the generator's
entity (or subentity) boundaries are not included in estimates of the
emissions intensity of the entity\'s (or subentity's) product output,
but should be included in a separate subentity report.

In general, emission reductions are intended to recognize actions that
contribute to reducing the energy intensity of the U.S. generating
sector on the whole. For energy generators, these actions can be
categorized into two types: those that reduce the emissions intensity of
an entity's own generation, and those that reduce demand for other, more
emitting sources (avoided emissions). Reporters should follow five steps
to estimate emission reductions associated with exported power:

1.  Estimate total generation and emissions for each energy type.

2.  Distinguish between energy used internally versus exported.

3.  Estimate reductions from exported energy due to improvements to
    historical emissions intensity.

4.  Estimate reductions from exported energy associated with incremental
    changes in generation.

5.  Calculate total reporting year reductions from exported energy.

**Step 1: Estimate total generation and emissions for each energy type**

The total quantities of power generation and associated emissions should
be estimated for each type of energy generated. Methods for estimating
emissions from power generation can be found in the Inventory Chapter
(Chapter 1) of the Technical Guidelines.

**Step 2: Distinguish between energy used internally versus exported**

Reporters must track the quantities of electrical and thermal energy
that are used within entity (or subentity) boundaries versus exported
outside of the entity (or subentity) boundaries. For entities that sell
some portion of their thermal or electrical generation, sales data and
records will be the most easily referenced source of this information.
Any power that is not exported can be assumed to be used internally. In
cases where the output of a single generating unit is split into
internal use and power exports, emissions must be allocated to internal
use and exports based on the quantities used internally and exported:

**(Exported Generation / Total Generation) \* Total Emissions= Exported
Emissions**

**Step 3: For each type of energy exported, estimate reductions from
energy exports due to improvements to historical emissions intensity**

Reductions that result from changes to an entity's emissions intensity
are calculated by multiplying the difference between an entity's Base
Year and Reporting Year emissions intensity by the quantity of energy
generated in the Base Period (after accounting for acquired and divested
capacity, see Section 2.4.1, above):

**Reductions~Base\ Generation~ = (E~B~/O~B~) -- (E~R~/O~R~) \* Total
Exported Generation ~B~ (MWh or MMBtu)\
**

**Where:**

**E = greenhouse gas emissions (in tons)**

**O = output measure (in selected measure)**

**E/O = GHG intensity**

**B = base period**

**R = reporting year.**

**Step 4: For each type of energy exported, estimate reductions from
energy exports associated with incremental changes in generation**

Any change in the quantity of exported energy from the Base Period to
the Reporting Year is considered "incremental," and is used to calculate
the avoided emissions resulting from the associated change in demand on
other generators. These reductions are calculated by multiplying the
quantity of Incremental Generation by the difference between an entity's
Reporting Year emissions intensity and the appropriate Benchmark
emissions value. Avoided emissions should be calculated as follows
separately for each region as each region has its own unique avoided
emission benchmark:

***Reductions ~Incremental~ = (Regional Avoided Emissions***
***Benchmark Intensity -- (E~R~/O~R~)) \****

**Incremental Generation (MWh or MMBtu)**

**Where:**

**E = greenhouse gas emissions (in tons)**

**O = output measure (in selected measure)**

**(E/O) = GHG intensity**

**R = reporting year**

**Step 5: Calculate total reporting year reductions for exported
energy**

Total reductions can be calculated by adding the results of steps 3 and
4, above. Alternatively, any entity can calculate their Total Reporting
Year Emission Reductions by using the following integrated formula. This
formula may be used even if the entity did not generate energy in its
base period. Note that this formula can only be used if incremental
generation was restricted to one unique region and one unique avoided
emissions benchmark. Alternatively, if a reporter has incremental
generation in multiple regions, it would have to calculate this formula
for each region, or calculate its weighted average avoided emissions
benchmark and use it in the formula below:

> **Emission Reductions~Reduction\ Year~ = 'Exported'
> Emissions~Base\ period~ +**
>
> **\[Incremental Generation \* Regional Avoided Emissions**
> **Benchmark\] -- 'Exported' Emissions~Reduction\ Year~**

**Where:**

**Avoided Emissions** **Benchmark**

**= DOE-determined regional** **emissions intensity value for energy
generation (tons CO~2~ / MWh or tons CO~2~ / MMBtu)**

**Emission Reductions~Reduction\ Year~**

**= Emission Reductions reportable during the reporting year (tons
CO~2~)**

**Incremental Generation = Increase in** **total quantity of power
exported** **during the Reduction Year, relative to the Base period (MWh
or MMBtu)**

**'Exported' Emissions~Base\ period~ = Total emissions associated with
power exports in the Base period (tons CO~2~)**

**'Exported' Emissions~Reduction\ Year~= Total emissions associated with
power exports in the Reduction Year (tons CO~2~)**

##### 2.4.6.2. Estimating Emission Reductions from Renewable and Waste-to-energy Generation

Under the original 1605(b) Program, all types of energy generation,
including renewable generation (e.g. biomass generation, solar, wind,
hydro) and waste-to-energy generation (e.g., waste oil burning, tire and
tire product burning, municipal waste burning and landfill gas
generation) are treated equally with respect to calculating emission
reductions. Reporters should refer to the following sections of the
Inventory Chapter of the Technical Guidelines for guidance on estimating
emissions from different types of energy generation:

-   Part C, "Stationary Combustion:" Petroleum-based waste and byproduct
    fuels (e.g. tires, waste oil), biogenic fuels (e.g. bagasse, wood,
    wood waste, ethanol), municipal solid waste

-   Part E, **"**Industrial Processes:" Coalmine methane, landfill
    methane, wastewater sludge and methane

-   Part F, "Indirect Emissions:" Renewables

## 

##### 2.4.6.3. Estimating Emission Reductions from CHP Generators

Combined Heat and Power (CHP, also known as cogeneration) refers to a
broad class of generators that simultaneously produce electricity and
useful thermal energy, which can be used as process heat, to produce
steam, to drive absorption chillers, or for a variety of other heating
and cooling purposes.

While manufacturers operate some 90 percent of the CHP systems in the
United States, CHP plants vary widely in their size, fuel sources, and
application. Although CHP generators are particularly well suited to
processes that have a concurrent demand for thermal and electrical
energy, it is common for CHP operators to sell some portion of their
thermal or electrical generation if it is in excess of their demand
load. In some cases, CHP plants are operated exclusively as merchant
plants, where both of the energy outputs are sold in their entirety.
While the scale and the relative proportions of heat and electricity
sold or used on-premises may vary, CHP generators fall into one of the
following arrangements:

-   Operator uses all heat and electricity on premises.

-   Operator uses all heat on premises, sells all or some portion of
    electricity.

-   Operator uses all electricity on premises, sells all or some portion
    of heat.

-   Operator uses some portion of heat and electricity on premises,
    sells remaining.

-   Operator sells all heat and all electricity off-premises.

Emission reductions for CHP generators are calculated in the same manner
as they are for conventional generators. Due to the fact that CHP
generates multiple energy streams from a single fuel, and the variety of
possible internal use/export arrangements, however, CHP operators must
perform the additional step of allocating overall plant emissions to
thermal and electrical generation before calculating reductions. This is
accomplished in the two steps outlined below: first converting total
fuel consumption to emissions, and then allocating these emissions to
fuel consumption for each generation stream based on the efficiencies of
thermal and electrical power generation.. nce emissions have been
calculated for each generation stream, reductions should be calculated
using the methods described under 'Estimating Reductions Associated with
Energy Generation and Exports,' above.

**2.4.6.3.1. Calculate Total Plant Emissions**

The first step in allocating emissions to electrical and thermal
generation is to determine the total quantity of emissions generated by
the CHP plant. Reporters should refer to Part C of the Inventory Chapter
of the Technical Guidelines, "Stationary Combustion," for guidance on
calculating emissions from thermal and electrical power generators.

2.  **Allocate Emissions Electricity and Thermal Generation**

The following formulas allocate emissions to the thermal and electrical
generating streams of the CHP plant based on the efficiency of thermal
and electrical generation:[^194]

> **CHP Plant Emissions~Thermal~** **= Emissions~Total~** **\* (O~T~/
> E~T~) / ((O~T~** **/ E~T~) + (O~E~/ E~E~))**
>
> **CHP Plant Emissions~Electricity~** **= Emissions~Total~** **-
> Emissions~Thermal~**

Where:

> **CHP Plant Emissions~Thermal~** **= Emissions attributable to thermal
> generation**
>
> **CHP Plant Emissions~Electricity~** **= Emissions attributable to
> electricity generation**
>
> **CHP Plant Emissions~Total~** **= Total emissions from the CHP
> plant**
>
> **CHP Plant** **O~Thermal~** **(O~T~)** **= Thermal generation,
> measured in MMBtu**
>
> **CHP Plant** **O~Electricity~** **(O~E~)~E~= Electrical generation,
> measured in MMBtu**[^195]
>
> **CHP Plant** **E~Thermal~** **(E~T~)** **=** **Efficiency of thermal
> energy generation, expressed**
>
> **as a decimal percentage**
>
> **CHP Plant** **E~Electricity~** **(E~E~)~E~=** **Efficiency of
> electrical energy generation, expressed as a decimal percentage**

## 

## 

## 

## 

## 

## 

## 

## 

## 

## 

## 

## 

## 

## 

## 

If the efficiency of thermal energy generation (E~Thermal~) is unknown,
reporters may use a default value of 0.8^200^. If the efficiency of
electrical generation (E~Electricity~) is unknown, reporters may use a
default value of 0.35^200^.

**2.4.6.3.3. Calculate Reductions**

Once emissions have been allocated to thermal and electrical generation,
reductions for each (as applicable) can be calculated using the methods
described under 'Estimating Reductions Associated with Energy Exports,'
above.

### 2.5 Determining Registered Emission Reductions

For qualified reports, the quantity of registered emission reductions
for any given Reporting Year is determined by summing the net changes in
emissions, avoided emissions and sequestration for all subentities
included in the entity's report to EIA. Using the formulas described in
Section 2.4, above, any positive sum would be a net reduction, and any
negative sum would be a net emissions increase. If the entity reported a
net increase in emissions for a preceding year and that emission
increase had not yet been fully offset by net emission reductions in
subsequent years, the remaining quantity of emission increases (a
negative number) would be summed with any net change for the current
Reporting Year. The remainder, if positive, is the quantity of the
entity's emission reductions eligible for registration.

Entities that wish to register emission reductions in any subsequent
year must continue to submit qualifying reports for every year. These
reports must include an annual assessment of their emission reductions
and meet all of the other requirements for registering reductions, even
if the assessment indicates that the entity did not achieve a net
reduction of emissions.

The entity may also report offset reductions generated by non-reporting
third parties. The quantity of offset emission reductions that is
eligible for registration is determined independently for each third
party, using the same procedure followed by each reporting entity and
described above. For any given Reporting Year, this means that a
reporting entity might not qualify for registered emission reductions,
although it might still be receive recognition for registered reductions
achieved by third parties covered by its report (or vice versa).

Summary data will be made available by EIA indicating, for each
Reporting Year, the registered reductions attributed to each reporting
entity and the third parties for whom it reported, including information
on any net increases in emissions not yet offset by subsequent emission
reductions. In addition, EIA will provide cumulative totals of the
registered reductions and any net increases in emissions not yet offset
by subsequent emission reductions.

### 2.6 Revising Previously Accepted Reports of Emission Reductions

Once a report on emission reductions has been accepted by EIA under the
revised guidelines, it may be revised by the reporting entity only under
certain conditions specified below and in the General Guidelines.
Previously reported net changes in emissions, avoided emissions and
sequestration for an entity or any of the third parties for which it is
reporting may be made only to correct significant errors or omissions,
including errors resulting from the estimation, rather than the
measurement, of reporting year terrestrial carbon stocks. When using
actual measurement of carbon stocks to correct prior year estimates,
reporters may avoid revisions of multiple annual reports by assuming
that all of the error occurred in the current reporting year. Such
corrections may be submitted at any time and must be accompanied by a
description of the corrections made, the significance of their effects
on the net changes in emissions reported and an explanation of why they
were needed. Previously submitted reports on emission reductions may not
be modified to incorporate subsequent improvements in emission
measurement or estimation techniques, nor may they be modified to
incorporate reductions associated with acquisitions or divestitures that
occurred after the affected reporting year.

## Glossary

\[*Note to users*: The Glossary provides definitions and explanations
for new terms used primarily in the draft Technical Guidelines, but also
references terms defined in the General Guidelines, 10 CFR § 300.2.\]

**Activity** **of small emitter:** See General Guidelines, 10 CFR §
300.2

**Afforestation:** The establishment of forest or forest stands on lands
that have not been recently forested.

**Aggregator:** See General Guidelines, 10 CFR § 300.2

**Agroforestry:** A land-use system that involves deliberate retention,
introduction, or mixture of trees or other woody perennials in crop and
animal production systems to take advantage of economic and/or
ecological interactions among the components.

**Anaerobic lagoon:** A liquid-based organic waste management
installation characterized by waste residing in water at a depth of at
least 6 feet for periods of 30 to 200 days.

**Anaerobic decomposition:** Decomposition in the absence of oxygen, as
in an anaerobic lagoon or digester, which produces CO~2~ and CH~4~.

Anthropogenic: See General Guidelines, 10 CFR § 300.2

**Avoided emissions:** See General Guidelines, 10 CFR § 300.2

**Base period:** See General Guidelines, 10 CFR § 300.2

**Base value:** See General Guidelines, 10 CFR § 300.2

**Biofuels:** Liquid fuels and blending components produced from biomass
(plant) feedstocks, used primarily for transportation.

**Biogenic emissions:** See General Guidelines, 10 CFR § 300.2

**Biomass:** Non-fossilized organic matter available on a renewable
basis, including organic material (both living and dead) from above and
below ground, e.g., trees, crops, grasses, tree litter, roots, animals,
and animal waste. Biomass includes forest and mill residues,
agricultural crops and residues, wood and wood residues, animal wastes,
livestock operation residues, aquatic plants, fast-growing trees and
plants, and the organic portion of municipal and relevant industrial
wastes.

Boundary: See General Guidelines, 10 CFR § 300.2

**Calcining:** The process of thermally decomposing carbonate into
quicklime, as in cement manufacturing.

**Carbon cycle:** The flow of carbon through the atmosphere, ocean,
terrestrial biosphere, and lithosphere. Carbon exchange between carbon
pools is driven by chemical, physical, geological, and biological
processes. Also see **Carbon pool** below.

**Carbon dioxide equivalent (CO~2~e):** See General Guidelines, 10 CFR §
300.2

**Carbon flow/carbon flux:** The movement of carbon from one carbon pool
to another, expressed as a quantum transfer (flow), or as a rate per
unit time (flux).

**Carbon pool:** Any reservoir of carbon. The four pools are atmosphere,
biosphere, oceans and sediments.

**Carbon stocks:** See General Guidelines, 10 CFR § 300.2

**Chlorofluorocarbon (CFC):** Any of the various compounds of carbon,
hydrogen, chlorine, and fluorine, typically used as refrigerants and for
other purposes.

Climate Leaders: See General Guidelines, 10 CFR § 300.2

Climate VISION: See General Guidelines, 10 CFR § 300.2

**Cogeneration facility:** A facility producing electricity and another
form of useful energy (such as heat or steam) through sequential use of
energy.

**Coke:** The solid black hydrocarbon left as a residual after the
volatile hydrocarbons have been removed from bitumen by distillation. It
is a fuel product often used in metal processing as a fuel and a
reduction agent for oxide compounds, the use of which results in carbon
dioxide emissions.

**Conversion factor:** A coefficient that converts units of one
measurement system into corresponding units in another measurement
system.

**Cropland:** A land cover/use category that includes areas used for the
production of crops for harvest.

***De minimis* emissions:** See General Guidelines, 10 CFR § 300.2

**Deforestation:** The removal of a forest stand where the land is put
to a nonforest use.

**Department** or **DOE:** See General Guidelines, 10 CFR § 300.2

**Direct emissions:** See General Guidelines, 10 CFR § 300.2

**Direct measurement:** Quantification of the greenhouse gas components
of an exhaust stream by continuous emissions monitoring (CEM) or
sufficient periodic sampling to closely approximate continuous
monitoring.

**Direct monitoring:** See Direct measurement

**Distributed energy:** See General Guidelines, 10 CFR § 300.2

**Double reporting**: When one entity submits emission or reduction data
more than once or when two or more entities report the same emission or
reduction.

**EIA** or **Energy Information Administration**: See General
Guidelines, 10 CFR § 300.2

**Ecosystem carbon components:**

> **Live tree --** A living woody perennial plant (capable of reaching
> at least 15 feet in height) with a diameter at breast height greater
> than 2.5 cm (1 inch), including the carbon mass in roots with
> diameters greater than 0.2 to 0.5 cm (note the specific diameter
> threshold will depend on sampling/estimation methods), stems,
> branches, and foliage.
>
> **Tree seedling --** A trees less than 2.5 cm (1 inch) diameter at
> breast height.
>
> **Standing dead tree --** A dead tree of at least 2.5 cm diameter at
> breast height that has not yet fallen, including the carbon mass of
> coarse roots, stems, and branches.
>
> **Understory vegetation --** Roots, stems, branches, and foliage of
> tree seedlings, shrubs, herbs, forbs, and grasses.
>
> **Forest floor** **--** Fine woody debris (smaller than 7.5 cm), tree
> litter, humus, and fine roots in the organic forest floor layer above
> mineral soil.
>
> **Down dead wood --** Logging residue and other coarse dead wood on
> the ground (greater than 7.5 cm diameter), as well as stumps and the
> coarse roots of stumps.
>
> **Soil --** Includes fine roots and all other organic carbon not
> included in the above pools, to a depth of one (1) meter.
>
> **Harvested wood** -- Wood removed from the forest ecosystem for the
> processing of various products. Logging debris (slash) left in the
> forest after harvesting is not included.

**Emissions:** See General Guidelines, 10 CFR § 300.2

**Emissions coefficient:** A unique value for scaling emissions to
activity data in terms of a standard rate of emissions per unit of
activity (e.g., pounds of carbon dioxide emitted per Btu of fossil fuel
consumed).

**Emissions factor:** see Emissions coefficient

**Emissions, fugitive:** Any unintentional release of greenhouse gases
to the atmosphere, including methane from the processing, transmission,
and/or transportation of fossil fuels, HFCs from stationary and mobile
air-conditioning and refrigeration equipment, SF~6~ from electric power
distribution, and methane from solid waste landfills.

**Emissions intensity**: See General Guidelines, 10 CFR § 300.2

**Emissions, process:** Emissions inherent in a productive process, as
in cement or ammonia manufacture, as distinguished from those resulting
from fuel combustion.

**Emissions source:** A discrete process, occurring at a particular
location, which emits one or more Greenhouse Gases.

**Engineered sequestration:** An engineered process whereby carbon
dioxide is captured from the point of emission and then stored in
underground reservoirs (geologic sequestration), dissolved in deep
oceans, or converted to rock-like solid materials.

**Enteric fermentation:** Animal digestion aided by methane-generating
microbes in the animal rumen and intestine that produces greenhouse gas
emissions, primarily methane.

**Entity** or **reporting entity:** See General Guidelines, 10 CFR §
300.2

**Entity boundary:** The limit in the scope of coverage for an entity's
emission inventory and emission reduction report.

**Entity statement:** See General Guidelines, 10 CFR § 300.5

**Equity share:** The percentage interest in ownership, benefits, or
control that may govern entitlements to emission reductions by
participants in collective undertakings.

**Estimation method:** The technique, including key assumptions and data
sources, used by a 1605(b) participant to derive reported emissions,
emission reductions, and/or sequestration where actual measurement is
not possible or practical.

**Financial control:** See General Guidelines, 10 CFR § 300.4(a)(1)

**First reduction year:** See General Guidelines, 10 CFR § 300.2

**Flaring**: The combustion of non-utilized gases prior to release into
the atmosphere. See also Venting

**Forest land**: Land at least 10 percent stocked by forest trees of any
size, or formerly having such tree cover, and not currently developed
for non-forest uses. The minimum area considered for classification is
one (1) acre.

**Forest management**: The practical application of biological,
physical, quantitative, managerial, economic, social, and policy
principles to the regeneration, tending, protection, harvest, access,
utilization, and conservation of forests to meet specified goals and
objectives while maintaining the productivity of the forest.

**Fugitive emissions:** See General Guidelines, 10 CFR § 300.2

**General Guidelines**: The emission and emission reduction Guidelines
that appear in Part 300 of the U.S. Code of Federal Regulations.

**Geologic sequestration:** A type of engineered sequestration, where
captured carbon dioxide is injected for permanent storage into
underground geologic reservoirs, such as oil and natural gas fields,
saline aquifers, or abandoned coal mines.

**Global warming potential (GWP):** An index used to compare the
relative radiative forcing of different gases without directly
calculating the changes in atmospheric concentrations. GWPs are
calculated as the ratio of the radiative forcing that would result from
the emission of one kilogram of a greenhouse gas to that from the
emission of one kilogram of carbon dioxide over a fixed period of time,
such as 100 years.

**Grassland:** Rangelands and pasturelands that are not considered
cropland and would not become forestland without human intervention.

**Greenhouse gases (GHGs):** See General Guidelines, 10 CFR § 300.2

**Heating value:** The amount of thermal energy released per unit of a
fuel that is burned completely.

**Hydrofluorocarbons (HFCs):** A class of anthropogenically created
chemical compounds composed of one or more carbon atoms and varying
numbers of hydrogen and fluorine atoms. Most HFCs have potent radiative
forcing effects, with 100-year GWPs generally between 1,300 and 12,000
times that of carbon dioxide.

**Incidental lands:** See General Guidelines, 10 CFR § 300.2

**Independent verifier:** See General Guidelines, 10 CFR § 300.11

**Independent verification:** See General Guidelines, 10 CFR § 300.11

**Indirect emissions:** See General Guidelines, 10 CFR § 300.2

**Intergovernmental Panel on Climate Change (IPCC):** A panel
established jointly by the World Meteorological Organization and the
United Nations Environmental Program in 1988 to assess scientific,
technical and socio-economic information relevant to climate change, its
potential impacts, and options for adaptation and mitigation.

**Inventory:** A quantified account of an entity's total Greenhouse Gas
emissions.

**Landfill gas:** Gas that is generated by the decomposition of organic
material at landfill disposal sites. The average composition of landfill
gas is approximately 50 percent methane and 50 percent carbon dioxide
and water vapor by volume. The methane percentage, however, can vary
from 40 to 60 percent, depending on several factors including waste
composition (e.g. carbohydrate and cellulose content). The methane in
landfill gas may be vented, flared, combusted to generate electricity or
useful thermal energy on-site, or injected into a pipeline for
combustion off-site.

**Large emitter:** See General Guidelines, 10 CFR § 300.2

**Life cycle:** The progression of a product or facility through its
service life.

**Look-up tables:** Reference tables, typically provided to relate
values of an observable parameter to corresponding values of less easily
observed variables.

**Managed carbon stocks**: Stocks that are affected by human decision or
action. Examples include managed forest, engineered carbon sinks, or
certain agricultural practices.

**Mass balance:** A method for calculating emissions based on the mass
and composition of fuel inputs, appropriate emissions factors, and
combustion performance.

**Materials balance calculation:** A computation of carbon flow through
an industrial process.

**Mineral soils:** A soil consisting predominantly of, and having its
properties determined predominantly by, mineral matter. Usually contains
less than 200 g/kg organic carbon (less than 120-180 g/kg if saturated
with water), but may contain an organic surface layer up to 30 cm thick.

**Mobile source emissions:** Transportation emissions, plus emissions
from small engines such as lawnmowers and equipment used at commercial
and industrial sites, non-road equipment used in farming and forestry,
at airports, and at railroad and marine terminals.

**Municipal solid waste:** Residential solid waste and some
non-hazardous commercial, institutional, and industrial wastes.

**Natural disturbances:** Processes or events such as insect outbreaks,
fire, disease, flooding, windstorms and avalanches that cause ecosystem
change.

**Net carbon flow:** The sum of all transfers of carbon between the land
and the atmosphere over a specified period. See also Carbon flow/carbon
flux

**Net emission reductions** or **net entity-wide emission reductions:**
See General Guidelines, 10 CFR § 300.2

**Offset:** See General Guidelines, 10 CFR § 300.2

**Operational control:** The authority to introduce and implement
operating policies in an organization.

**Operations data system:** A data collection system that reports the
physical quantities of inputs utilized and products manufactured. These
data are typically produced for management and regulatory compliance
needs and are usually held at the facility level in the organization.

**Organic growth/decline:** Increases/decreases in greenhouse gas
emissions as a result of changes in production levels, net investment in
new capacity, and changes in product mix, as distinguished from
acquisitions and divestitures.

**Organic soils:** Soil materials that are saturated with water and have
174g/kg or more organic carbon if the mineral fraction has 500 g/kg or
more clay, or 116 g/kg organic carbon if the mineral fraction has no
clay, or has proportional intermediate contents. If these materials were
never saturated with water they would have 203 g/kg or more organic
carbon.

**Organizational boundary**: The scope of the entity covered by 1605(b)
reporting, as defined in the entity statement. Generally, the
organizational boundary of an entity encompasses all facilities and
operations that are under the management control of the entity, which
usually includes all land, facilities and vehicles that are wholly or
majority owned or under long-term lease by the entity, as well as
certain other facilities, vehicles or land that are under the management
control of the entity. See also Entity Boundary

**Outsourcing:** Contracting out activities by an entity to other
businesses, where the output of the outsourced activity is later
re-integrated into the entity's products or is otherwise integral to the
entity's operations.

**Permanence:** The longevity of carbon in a carbon sink (such as forest
land).

**Perfluorocarbons (PFCs):** A group of man-made chemicals composed of
one or six carbon atoms and four to fourteen fluorine atoms, containing
no chlorine. PFCs are compounds derived from hydrocarbons by replacement
of hydrogen atoms by fluorine atoms. PFCs have several commercial uses
and are emitted as a byproduct of aluminum smelting and semiconductor
manufacturing. PFCs have very high 100-year Global Warming Potentials
and are very long-lived in the atmosphere.

**Prescribed fire:** Intentionally set and managed forest burns, which
further specific resource management objectives.

**Process emissions:** See Emissions, process

**Process models:** Mathematical representations of ecosystem processes,
such as nitrogen and carbon cycles.

**Reforestation:** The re-establishment of forest cover, naturally or
artificially, on lands that have recently been harvested or otherwise
cleared of trees.

**Regeneration:** The natural (by natural seeding, coppice, or root
suckers) or artificial (by direct seeding or planting) process of
re-establishing tree cover on forestland.

**Registration:** See General Guidelines, 10 CFR § 300.2

**Reporting:** If an entity does not choose to report emissions in a
manner that conforms to the registration requirements, including those
set forth in §§ 300.6 and 300.7 of these Guidelines, then the entity may
choose to report on any emissions or any emission reductions by
complying with the other requirements of Part 300 of these Guidelines.

**Reporting entity:** See General Guidelines, 10 CFR § 300.2

**Reporting** **year:** See General Guidelines, 10 CFR § 300.2

**Sequestration:** See General Guidelines, 10 CFR § 300.2

**Simplified Inventory Estimation Tool (SIET):** See General Guidelines,
10 CFR § 300.2

**Silviculture:** The art and science of controlling the establishment,
growth, composition, health, and quality of forests and woodlands.

**Sink:** See General Guidelines, 10 CFR § 300.2

**Small emitter:** See General Guidelines, 10 CFR § 300.2.

**Source:** See General Guidelines, 10 CFR § 300.2

**Start year**: See General Guidelines, 10 CFR § 300.2

**Stationary sources**: Emission sources at fixed locations, such as
power plants, factories, refineries, mines, heating plants or waste
conversion facilities.

**Subentity:** See General Guidelines, 10 CFR § 300.2

**Sustainable Forest Management:** The practice of managing forests to
provide ecological, economic, social and cultural benefits for present
and future generations. For the purposes of 1605(b) reporting, a
determination of sustainably managed forests must be certified
consistent with provisions of the Technical Guidelines, Chapter 1.I.3.5.

**Technical Guidelines:** Detailed explanatory supplements to the
1605(b) General Guidelines.

**Terrestrial sequestration:** Biotic sequestration of carbon in above-
and below-ground biomass and soils.

**Total emissions**: See General Guidelines, 10 CFR § 300.2

**Total entity-wide emission reductions**: The sum of all annual changes
in emissions, carbon stocks and avoided emissions of the greenhouse
gases specifically identified in Section 300.6(f), determined in
conformance with §§ 300.7 and 300.8 of these Guidelines. In calculating
this total, decreases in emissions and increases in carbon stocks and
avoided emissions are expressed as positive values.

**Transportation sources****:** In the context of emissions,
transportation sources include vehicles that operate on roads and
highways, as well as non-road vehicles, engines, and equipment, but
exclude farm equipment associated with particular farm premises.
Examples of transportation sources include cars, trucks, buses,
earth-moving equipment, lawn and garden power tools, ships, railroad
locomotives, and airplanes.

**United States or U.S.:** See General Guidelines, 10 CFR § 300.2

**Venting:** Release of gases into the atmosphere without combustion.
See also Flaring

**Verification:** See General Guidelines, 10 CFR § 300.11

**Wood products**: Products derived from the harvested wood from a
forest, including fuel-wood and logs and the products derived from them
such as cut timber, plywood, wood pulp, paper, etc. Includes both
products in use and in disposal systems such as landfills (but which
have not yet decayed, releasing carbon to the atmosphere as carbon
dioxide and/or CH~4~).

[^1]: Source: Intergovernmental Panel on Climate Change, *Climate Change
    2001: The Scientific Basis* (Cambridge University Press, 2001), p.
    47.

[^2]: Intergovernmental Panel on Climate Change, *Climate Change 2001:
    The Scientific Basis* (Cambridge University Press, 2001), pp. 47,
    388.

[^3]: General Guidelines, § 300.2.

[^4]: General Guidelines, § 300.4 Selecting organizational boundaries.

[^5]: General Guidelines, § 300.2 Definitions, "Indirect Emissions."

[^6]: For many manufacturers and firms in service industries, fossil
    fuel combustion will be the largest source of direct emissions.
    Indirect emissions from electricity use, however, may be
    considerably larger than direct emissions from fossil fuel
    combustion for these reporters.

[^7]: Included are automobiles, trucks, buses, motorcycles, trains,
    subways, and other rail vehicles, aircraft, ships, barges, and other
    waterborne vehicles.

[^8]: Scrubbers are usually associated with large, coal-fired power
    generation equipment. Reporters estimating carbon dioxide emissions
    using continuous emission monitoring will have the carbon dioxide
    from scrubbers automatically included in the stack gas they are
    monitoring. Reporters using mass balance to estimate emissions from
    power plants with scrubbers will have to separately estimate
    scrubber carbon dioxide emissions and add them to the fuel-related
    carbon dioxide emissions.

[^9]: In-house steam generation for space heating or cogeneration is
    very common. Emissions from this source can be conveniently
    quantified by measuring the amount of fuel that has been combusted
    to raise the steam. Purchasing steam (or heat) from another party is
    less common.

[^10]: Available at web site: www.iso.ch.

[^11]: See the U.S. Environmental Protection Agency's Acid Rain web
    site: www.epa.gov/airmarkets/arp/index.html.

[^12]: All coal-fired units with a capacity greater than 25 MW and all
    new coal-fired units burning fuels with a sulfur content greater
    than 0.5 percent are required to install CEMs.

[^13]: A "standard cubic foot" is a cubic foot measured under "standard"
    conditions: atmospheric pressure, 60 degrees F.

[^14]: In some cases it may be possible to extract methane emission
    estimates from monitoring non-methane volatile organic compounds
    (NMVOC) because the monitors may be tracking both total organic
    compounds and NMVOCs.

[^15]: Environmental Protection Agency, *Compilation of Air Pollutant
    Emission Factors* (AP-42), Fifth Edition, Volume I: Stationary Point
    and Area Sources, pages 1.2-11 (6/96), 1.3-2.0 (9/98), 1.3-2.11
    (7/00), 1.3-14 (9/98), 1-40 (9/98), 1.4-8 (7/98), 1.5-3 (6/96),
    1.7-4.2 (9/98), and 3-1-12 (4/00).

[^16]: Energy Information Administration, Documentation for Emission of
    Greenhouse Gases in the United States 2003 (May 2005), pp. 209-210,
    web site:
    www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

[^17]: American Petroleum Institute, \"Compendium of Greenhouse Gas
    Emissions Methodologies for the Oil and Gas Industry\", February
    2004.

[^18]: Energy Information Administration, Documentation for Emission of
    Greenhouse Gases in the United States 2003 (May 2005), pp. 214-215,
    web site:
    www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

[^19]: See the EIA's voluntary reporting web site:
    www.eia.doe.gov/oiaf/1605/coefficients.html.

[^20]: U.S. Environmental Protection Agency, Office of Atmospheric
    Programs, Climate Protection Partnerships Division, Climate Leaders
    Greenhouse Gas Inventory Protocol Core Module Guidance, *Direct
    Emissions from Mobile Combustion Sources,* October 2004, web site:
    www.epa.gov/climateleaders/docs/mobilesourceguidance.pdf

[^21]: U.S. Environmental Protection Agency, *Inventory of U.S.
    Greenhouse Gas Emissions and Sinks: 1990 -- 2003* (April 15, 2005),
    web site:
    yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterPublicationsGHGEmissionsUSEmissionsInventory2005.html.

[^22]: U.S. Energy Information Administration, *Emissions of Greenhouse
    Gases in the United States, 2001*. December 2002, p. 52, web site:
    www.eia.doe.gov/oiaf/1605/1605aold.html.

[^23]: U.S. Environmental Protection Agency, Office of Atmospheric
    Programs, Climate Protection Partnerships Division, Climate Leaders
    Greenhouse Gas Inventory Protocol Core Module Guidance, *Direct
    Emissions from Mobile Combustion Sources,* October 2004, web site:
    www.epa.gov/climateleaders/docs/mobilesourceguidance.pdf.

[^24]: Intergovernmental Panel on Climate Change, *Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories,* June 2001, web site:
    www.ipcc-nggip.iges.or.jp/public/gp/english/.

[^25]: Reporters should use higher heating values, which are commonly
    used in the United States. Internationally, however, the "lower"
    heating value is used. For more information, see Intergovernmental
    Panel on Climate Change, *Greenhouse Gas Inventory Reference Manual:
    Revised 1996 IPCC Guidelines for National Greenhouse Gas
    Inventories*, Vol. 3 (Paris, France, 1997), web site:
    www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^26]: Intergovernmental Panel on Climate Change, *Revised 1996 IPCC
    Guidelines for National Greenhouse Gas Inventories: Reference
    Manual* (1997), Table 1-6,
    www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^27]: U.S. Environmental Protection Agency, *Inventory of U.S.
    Greenhouse Gas Emissions and Sinks: 1990 -- 2003,* Annex 3.2, April
    2005, web site:
    yosemite.epa.gov/OAR/globalwarming.nsf/content/ResourceCenterPublicationsGHGEmissionsUSEmissionsInventory2005.html.

[^28]: U.S. Environmental Protection Agency, Office of Atmospheric
    Programs, Climate Protection Partnerships Division, Climate Leaders
    Greenhouse Gas Inventory Protocol Core Module Guidance, *Direct
    Emissions from Mobile Combustion Sources* (October 2004), web site:
    www.epa.gov/climateleaders/docs/mobilesourceguidance.pdf.

[^29]: Energy Information Administration, *Documentation for Emissions
    of Greenhouse Gases in the United States 2003* (May 2005), web site:
    www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

[^30]: Intergovernmental Panel on Climate Change, *Greenhouse Gas
    Inventory Reference Manual* (Revised 1996 IPCC Guidelines for
    National Greenhouse Gas Inventories), web site:
    www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^31]: Intergovernmental Panel on Climate Change, *Good Proactive
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories* (June 2001), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/.*

[^32]: See www.epa.gov/climateleaders.

[^33]: World Business Council for Sustainable Development and World
    Resources Institute, *The Greenhouse Gas Protocol,* March 2004, web
    site:
    www.ghgprotocol.org/plugins/GHGDOC/details.asp?type=DocDet&ObjectId=MTM3NTc.

[^34]: American Petroleum Institute (API), *Compendium of Greenhouse Gas
    Emissions Estimation Methodologies for the Oil and Gas Industry*
    (February, 2004), web site:
    api-ec.api.org/filelibrary/2004_COMPENDIUM.pdf.

[^35]: U.S. Environmental Protection Agency, Office of Atmospheric
    Programs, Climate Protection Partnerships Division, Climate Leaders
    Greenhouse Gas Inventory Protocol Core Module Guidance, *Direct
    Emissions from Mobile Combustion Sources* (October 2004), web site:
    www.epa.gov/climateleaders/docs/mobilesourceguidance.pdf.

[^36]: U.S. Environmental Protection Agency, *Inventory of U.S.
    Greenhouse Gas Emissions and Sinks: 1990 -- 2003,* Annex 3.2, April
    2005, web site:
    yosemite.epa.gov/OAR/globalwarming.nsf/content/ResourceCenterPublicationsGHGEmissionsUSEmissionsInventory2005.html.

[^37]: Intergovernmental Panel on Climate Change, *Greenhouse Gas
    Inventory Reference Manual* (Revised 1996 IPCC Guidelines for
    National Greenhouse Gas Inventories)*,* web site:
    www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm. The *IPCC Good
    Proactive Guidance and Uncertainty Management in National Greenhouse
    Gas Inventories* updates the nitrous oxide emissions factors for
    gasoline vehicles. See Table 2.7 on p. 2.47, web site:
    www.ipcc-nggip.iges.or.jp/public/gp/english/.

[^38]: U.S. Environmental Protection Agency, Office of Atmospheric
    Programs, Climate Protection Partnerships Division, Climate Leaders
    Greenhouse Gas Inventory Protocol Core Module Guidance, *Direct
    Emissions from Mobile Combustion Sources* (October 2004), web site:
    www.epa.gov/climateleaders/docs/mobilesourceguidance.pdf.

[^39]: U.S. Environmental Protection Agency, *Inventory of U.S.
    Greenhouse Gas Emissions and Sinks: 1990-2001*, Annex E (September
    23, 2003), EPA 430-R-03-004, pp. E-11 to E-13. All values were
    calculated from Tables E-9 through E-13, web site:
    http://yosemite.epa.gov/oar/globalwarming.nsf/UniqueKeyLookup/LHOD5MJTA3/\$File/2003-final-inventory_annex_e.pdf.

[^40]: U.S. Environmental Protection Agency, *Inventory of U.S.
    Greenhouse Gas Emissions and Sinks: 1990-2001*, Table E-14
    (September 23, 2003), Annex E, EPA 430-R-03-004, pg. E-13, web site:
    http://yosemite.epa.gov/oar/globalwarming.nsf/UniqueKeyLookup/LHOD5MJTA3/\$File/2003-final-inventory_annex_e.pdf.

[^41]: Intergovernmental Panel on Climate Change, *Greenhouse Gas
    Inventory Reference Manual* (Revised 1996 IPCC Guidelines for
    National Greenhouse Gas Inventories)*,* Table 1-47, pp. 1.89, web
    site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^42]: *Ibid.*

[^43]: Oak Ridge National Laboratory, *Transportation Energy Data Book*,
    Energy Efficiency and Renewable Energy program, U.S. Department of
    Energy, web site: http://cta.ornl.gov/data/index.html.

[^44]: This is the case for carbon dioxide, and probably the case for
    nitrous oxide and methane.

[^45]: Intergovernmental Panel on Climate Change, *Greenhouse Gas
    Inventory Reference Manual* (Revised 1996 IPCC Guidelines for
    National Greenhouse Gas Inventories)*,* Table 1-47, p. 189, web
    site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^46]: Intergovernmental Panel on Climate Change, *Greenhouse Gas
    Inventory Reference Manual* (Revised 1996 IPCC Guidelines for
    National Greenhouse Gas Inventories)*,* Tables 1-50 and 1-51, pp.
    196-197, web site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^47]: Intergovernmental Panel on Climate Change, *Greenhouse Gas
    Inventory Reference Manual* (Revised 1996 IPCC Guidelines for
    National Greenhouse Gas Inventories)*,* Tables 1-50 and 1-51, pp.
    196-197, web site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^48]: Intergovernmental Panel on Climate Change, *Good Proactive
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories* (June 2001), web site:
    www.ipcc-nggip.iges.or.jp/public/gp/english/.

[^49]: In particular, reporters should refer to subsection 1.E.4 for a
    list of sector-specific guidance resources.

[^50]: U.S. Energy Information Administration, *Emissions of Greenhouse
    Gases in the United States 2004* (December 2005), web site:
    ftp://ftp.eia.doe.gov/pub/oiaf/1605/cdrom/pdf/ggrpt/057304.pdf.

[^51]: *IBID*.

[^52]: Available at web site: www.iso.ch.

[^53]: Reporters should refer to subsection 1.E.4 for a list of
    sector-specific guidance and references.

[^54]: U.S. Environmental Protection Agency, AP-42 Series, "Introduction
    to AP-42," Volume I, Fifth Edition (January 1995), web site:
    www.epa.gov/ttn/chief/ap42/index.html.

[^55]: U.S. Environmental Protection Agency, *Inventory of Greenhouse
    Gas Emissions and Sinks: 1990-2003* (2005).

[^56]: Radian Corporation, *Nitrous Oxide Emissions from Adipic Acid
    Manufacturing* (Rochester, NY, January 1992).

[^57]: Intergovernmental Panel on Climate Change, NGGIP, *Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/.*

[^58]: The utilization factor accounts for the percent effectiveness of
    the control device based on issues related to installation,
    start-up, and maintenance of the device. For example, the higher the
    down time of the control device, the lower the utilization factor.

[^59]: Intergovernmental Panel on Climate Change, NGGIP, *Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/*.

[^60]: World Resources Institute/World Business Council for Sustainable
    Development. *Calculating CO~2~ Emission from the Production of
    Aluminum* (2003), web site:
    http://www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=OTAx&doOpen=1&ClickMenu=No.

[^61]: Intergovernmental Panel on Climate Change. *Revised 1996
    Guidelines for National Greenhouse Gas Inventories- Reference
    Manual* (1997) web site:
    www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^62]: Evidence suggests that there is little variation in CO~2~
    emissions from the consumption of carbon anodes for aluminum
    smelting among similar technologies. Accordingly, this value rating
    is higher than is typical of most default emissions factors.

[^63]: Intergovernmental Panel on Climate Change, NGGIP, *Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/*.

[^64]: Intergovernmental Panel on Climate Change. *Revised 1996
    Guidelines for National Greenhouse Gas Inventories- Reference
    Manual* (1997), web site:
    www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^65]: U.S. Environmental Protection Agency / International Aluminum
    Institute. *PFC Measurement Protocol* (May 2003), web site:
    www.climatevision.gov/sectors/aluminum/protocols.html.

[^66]: This Protocol provides guidance for individual facilities to
    develop detailed plans for sampling and analysis based on
    plant-specific technology, anode effect data, and chosen measurement
    instrumentation.

[^67]: Intergovernmental Panel on Climate Change, NGGIP, *Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/*.

[^68]: Intergovernmental Panel on Climate Change, *Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/*.

[^69]: Ibid.

[^70]: Ammonia production using hydrogen from byproduct streams does not
    generate any carbon dioxide emissions.

[^71]: These methods are derived from the following sources, which
    should be used as references:\
    - Intergovernmental Panel on Climate Change, *Revised 1996 IPCC
    Guidelines for National Greenhouse Gas Inventories* (1997), web
    site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.\
    - World Resources Institute/World Business Council for Sustainable
    Development, *Greenhouse Gas Protocol* *Corporate Accounting and
    Reporting Standard, Revised Edition* (March 2004), *CO2 Emissions
    from the Production of Ammonia*, Calculation Tools website:
    http://www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=OTAx&doOpen=1&ClickMenu=No.

[^72]: Industrial natural gas is usually sold on a volumetric basis, and
    which is typically "corrected for" with a Btu adjustment factor.
    Reporters should be able to derive Btu content from this
    information.

[^73]: Derived from: Energy Information Administration, *Documentation
    for Emissions of Greenhouse Gases in the United States 2003* (May
    2005), web site:
    www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.
    Carbon coefficients for other fossil fuels are also provided in this
    document.

[^74]: U.S. Environmental Protection Agency, *Synthetic Ammonia*, AP-42,
    5th Ed., Vol. 1, Ch. 8 (1993), web site:
    http://www.epa.gov/ttn/chief/ap42/index.html.

[^75]: Portland cement, which has a 95-percent clinker fraction, is the
    most commonly produced type of cement, and is the type of cement
    toward which these guidelines are oriented. Any additional carbon
    dioxide emissions associated with the production of masonry cement
    would be accounted for under lime production and not under cement
    production.

[^76]: This method is derived from the following sources, which should
    be used as references:\
    - Intergovernmental Panel on Climate Change, *Revised 1996 IPCC
    Guidelines for National Greenhouse Gas Inventories* (1997), web
    site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.\
    - World Resources Institute/World Business Council for Sustainable
    Development, *Greenhouse Gas Protocol Initiative* (2001), web site:
    www.ghgprotocol.org/standard/tools.htm.

[^77]: This method is derived from the following sources, which should
    be used as references:\
    - Intergovernmental Panel on Climate Change, *Revised 1996 IPCC
    Guidelines for National Greenhouse Gas Inventories* (1997), web
    site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.\
    - World Resources Institute/World Business Council for Sustainable
    Development, *Greenhouse Gas Protocol Initiative* (2001), web site:
    www.ghgprotocol.org

[^78]: This value is taken from the WRI/WBCSD's *Clinker-based
    Methodology for Calculating CO~2~ from the Production of Cement* and
    accounts for CO~2~ emissions from both the CaCO~3~ and MgCO~3~
    content of the raw materials.

[^79]: This method is derived from the U.S. Environmental Protection
    Agency, *ClimateLeaders Greenhouse Gas Inventory Protocol Core
    Module Guidance --* *Direct Emissions from Cement Sector*, web site:
    [www.epa.gov/climateleaders/docs/cement.pdf](http://www.epa.gov/climateleaders/docs/cement.pdf).

[^80]: Reporters using cement production mixes in between the values
    provided in Table 1.E.7 can estimate their "Clinker in the Cement
    Production Mix" value by interpolation (e.g. a reporter with an
    "Additive in the Blended Cement" value of 25 percent can assume a 71
    percent "Clinker in the Cement Production Mix" value).

[^81]: Intergovernmental Panel on Climate Change, *Revised 1996 IPCC
    Guidelines for National Greenhouse Gas Inventories* (1997) web site:
    www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm*.*

[^82]: Available at web site
    http://www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=OTAx&doOpen=1&ClickMenu=No.

[^83]: Intergovernmental Panel on Climate Change, *Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Emission Inventories* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/.*

[^84]: For guidance on estimating emissions using mass balance based on
    the carbon content of feedstock fuels, refer to Section 1.E.4.1.3,
    "Ammonia Production."

[^85]: The coke generated by integrated plants and coking facilities is
    identical.

[^86]: This discussion applies to all pig iron that is reduced to steel,
    regardless of whether the pig iron is produced on-site or purchased.

[^87]: Value taken from Intergovernmental Panel on Climate Change, *Good
    Practice Guidance and Uncertainty Management in National Greenhouse
    Gas Emission Inventories* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/.*

[^88]: Value taken from: World Resources Institute / World Business
    Council for Sustainable Development, *Greenhouse Gas Protocol
    Initiative - Calculating CO~2~ Emissions from the Production of Iron
    and Steel -* *Calculation Tools* web site:
    http://www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=OTAx&doOpen=1&ClickMenu=No.

[^89]: Intergovernmental Panel on Climate Change, *Revised IPCC
    Guidelines for National Greenhouse Gas Inventories* (1997), p.2.6.
    web site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^90]: Intergovernmental Panel on Climate Change. *Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Emission Inventories* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/.*

[^91]: See Part C, "Stationary Combustion*.*"

[^92]: Intergovernmental Panel on Climate Change, *Revised 1996 IPCC
    Guidelines for National Greenhouse Gas Inventories* (1997), web
    site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^93]: Rank is the degree to which peat has undergone thermal alteration
    to form coal. The higher the rank, the higher the carbon content,
    resulting in a higher heat value (HHV) per pound. Values for
    different coal ranks, measured in Btu, are as follows: Anthracite:
    approximately 14,000; Bituminous 12,800 to 15,000; Sub-bituminous A:
    12,600; Sub-bituminous B: 9,500 to 11,000; Sub-bituminous C: 8,000
    to 9,500; Lignite: 3,000 to 8,000.

[^94]: Intergovernmental Panel on Climate Change, *Revised 1996 IPCC
    Guidelines for National Greenhouse Gas Inventories* (1997).

[^95]: Energy Information Administration, *Emissions of Greenhouse Gases
    in the United States 1998, Appendix A: Estimation Methods* (November
    1999).

[^96]: It should be noted that some methane is also released from coal
    waste piles and abandoned mines. Coal waste piles are composed of
    rock and small amounts of coal that are produced during mining along
    with marketable coal. In some abandoned mines, methane can continue
    to be released from the surrounding strata for many years, although
    most available evidence indicates that methane flow rates decay
    rapidly once deep-mine coal production ceases.

[^97]: The Mining Safety and Health Administration (MSHA) records coal
    mine methane readings with concentrations of greater than 50 parts
    per million (ppm) methane. Readings below this threshold are
    considered non-detectable.

[^98]: U.S. Environmental Protection Agency, *Inventory of U.S.
    Greenhouse Gas Emissions and Sinks: 1990 -- 2001, Appendix F*, EPA
    430-R-03-004 (April 2003).

[^99]: *In situ* - in the seam prior to mining

[^100]: For additional information on the location of coal basins and
    state lines, reporters should consult the USGS Coal Resources web
    site: http://energy.cr.usgs.gov/coal/index.htm.

[^101]: U.S. Environmental Protection Agency, *Anthropogenic Methane
    Emissions in the United States: Estimates for 1990: Report to
    Congress*, EPA 430-R-93-003 (April 1993), p. 3-11.

[^102]: In addition to the sources listed above in Section 1.E.4,
    reporters should consult the following:\
    - International Petroleum Industry Environmental Conservation
    Association, *Petroleum Industry Guidelines for Reporting Greenhouse
    Gas Emissions* (2003), web site:
    www.ipieca.org/downloads/climate_change/GHG_Reporting_Guidelines.pdf.

    -U.S. Environmental Protection Agency/GRI, *Methane Emissions from
    the Natural Gas Industry, Volume 1: Executive Summary,*
    EPA-600/R-96-080a (1996), prepared by M. Harrison, T. Shires, J.
    Wessels, and R. Cowgill, eds. (Radian International LLC for National
    Risk Management Research Laboratory, Air Pollution Prevention and
    Control Division, Research Triangle Park, NC), web site:
    www.epa.gov/gasstar/pdf/emissions_report/1_executiveummary.pdf.

[^103]: Emissions associated with the combustion or use of
    petroleum-based products are not addressed in this section.
    Reporters should refer to Part C, "Stationary Combustion," and
    relevant sections within this Part to estimate these emissions.

[^104]: Flaring presents a unique situation in the oil and natural gas
    industries. While the majority of emissions from flaring result from
    combustion, flaring also releases significant quantities of
    non-combusted gases. According to the IPCC's *Good Practice
    Guidance* and *Revised 1996 IPCC Guidelines*, these releases should
    be accounted for as fugitive emissions.

[^105]: Taken from *Revised 1996 IPCC Guidelines for National Greenhouse
    Gas Inventories: Reference Manual, Energy* (1997), web site:
    [www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm](http://www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm).
    Where IPCC guidance refers to outdated versions of the U.S. EPA's
    AP-42 or the API Compendium, use most recent versions of these
    documents instead.

[^106]: Intergovernmental Panel on Climate Change, *Good Practice
    Guidance and Uncertainty Management for National Greenhouse Gas
    Inventories* (2000), web site:
    *[www.ipcc-nggip.iges.or.jp/public/gp/english/](http://www.ipcc-nggip.iges.or.jp/public/gp/english/).*
    Where IPCC guidance refers to outdated versions of the U.S. EPA's
    AP-42 or the API Compendium, use most recent versions of these
    documents instead.

[^107]: Available at web site www.epa.gov/ttn/chief/ap42/ch05/.

[^108]: Available at web site api-ep.api.org/index.cfm.

[^109]: Available at web site
    www.epa.gov/ttn/chief/eiip/techreport/volume08/index.html.

[^110]: Available at web site
    www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

[^111]: Available at web site
    www.api.org/ehs/climate/new/upload/2004_COMPENDIUM.pdf.

[^112]: Where IPCC guidance refers to outdated versions of the U.S.
    EPA's AP-42 or the API Compendium, use most recent versions of these
    documents instead.

[^113]: Human waste and other high-protein wastewater streams generate
    nitrous oxide emissions. These emissions are discussed in the
    Wastewater Handling section, directly below.

[^114]: U.S. Energy Information Administration, *Emissions of Greenhouse
    Gases in the United States 2002* (November 2003), web site:
    www.eia.doe.gov/oiaf/1605/gg03rpt/pdf/057302.pdf or
    www.eia.doe.gov/oiaf/1605/gg03rpt/index.html

[^115]: U.S. Environmental Protection Agency, *Inventory of U.S.
    Greenhouse Gas Emissions and Sinks: 1990-2003* (April 2005) web
    site:
    yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterPublicationsGHGEmissionsUSEmissionsInventory2005.html.

[^116]: In its *Inventory of U.S. Greenhouse Gas Emissions and Sinks:
    1990-2003*, the EPA uses BOD to estimate methane emissions from
    secondary treatment of wastewater in the pulp and paper industry due
    to better data availability.

[^117]: Commercial COD test kits are available from a variety of
    manufacturers, including Bioscience, Inc., Hanna Instruments, Thermo
    Electron Corporation, and Palintest Ltd.

[^118]: EPA Method 410.4 \-- Chemical Oxygen Demand. Data quality
    indicator table is available at web site
    www.epa.gov/region9/qa/datatables.html.

[^119]: This is the same method used to estimate industrial emissions in
    the U.S. Environmental Protection Agency's *Inventory of U.S
    Greenhouse Gas Emissions and Sinks: 1990-2003* (2005), web site:
    yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterPublicationsGHGEmissionsUSEmissionsInventory2005.html

[^120]: National Council for Air and Stream Improvement, Inc.,
    Calculation Tools for Estimating Greenhouse Gas Emissions from Pulp
    and Paper Mills, The Climate Change Working Group of the
    International Council of Forest and Paper Associations, Version 1.1,
    July 8, 2005, web site:
    http://www.ncasi.org/support/downloads/default.aspx.

[^121]: U.S. Environmental Protection Agency, *Inventory of U.S
    Greenhouse Gas Emissions and Sinks: 1990-2001* (2003), web site:
    yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterPublicationsGHGEmissions

    USEmissionsInventory2005.html

[^122]: Equal to the maximum potential methane produced per unit COD.
    Value taken from Intergovernmental Panel on Climate Change, *Revised
    1996 IPCC Guidelines for National Greenhouse Gas Inventories:
    Reference Manual- Chapter 6.* (1997), web site:
    www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^123]: Intergovernmental Panel on Climate Change, *Good Practice
    Guidance and Uncertainty Management for National Greenhouse Gas
    Inventories-Chapter 5* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/*.

[^124]: The ICFPA method using a ratio of COD to BOD to estimate an
    emissions factor (EF) is rated A.

[^125]: The ICFPA method using a default emissions factor (EF) is rated
    B.

[^126]: Adapted from Intergovernmental Panel on Climate Change, *Revised
    1996 IPCC Guidelines for National Greenhouse Gas Inventories:
    Reference Manual* (1997), web site:
    www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^127]: The other major gas is carbon dioxide, which is considered
    biogenic (part of the natural carbon cycle) and therefore does not
    need to be included in the emission estimates from this source.

[^128]: For a discussion of the treatment of emissions from the
    combustion of recovered methane, refer to the general discussion of
    waste, above.

[^129]: Intergovernmental Panel on Climate Change, *Revised 1996 IPCC
    Guidelines for National Greenhouse Gas Inventories: Reference
    Manual* (1997), web site:
    www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm .

[^130]: Intergovernmental Panel on Climate Change, *Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/*

[^131]: Energy Information Administration, *Documentation for Emissions
    of Greenhouse Gases in the United States 2003*(Washington, DC May
    2005), web site:
    www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2003).pdf.

[^132]: U.S. Environmental Protection Agency. *Inventory of U.S.
    Greenhouse Gas Emissions and Sinks: 1990-2003. (April,* 2005), web
    site:
    yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterPublicationsGHGEmissionsUSEmissionsInventory2005.html.\
    .

[^133]: Intergovernmental Panel on Climate Change, *Revised 1996 IPCC
    Guidelines for National Greenhouse Gas Inventories* (1997), web
    site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm*.*

[^134]: As described in the glossary, global warming potential is an
    index used to compare the relative radiative forcing of different
    gases without directly calculating the changes in atmospheric
    concentrations. GWPs are calculated as the ratio of the radiative
    forcing that would result from the emission of one kilogram of a
    greenhouse gas to that from the emission of one kilogram of carbon
    dioxide over a fixed period of time, such as 100 years.

[^135]: Usually the condenser vent.

[^136]: Default value from Intergovernmental Panel on Climate Change,
    *Greenhouse Gas Inventory Reference Manual: Revised 1996 IPCC
    Guidelines for National Greenhouse Gas Inventories* (1997), web
    site: www.ipcc-nggip.iges.or.jp/public/gl/invs1.htm.

[^137]: Intergovernmental Panel on Climate Change, *Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/.*

[^138]: For a detailed discussion of the various source categories of
    HFC, PFC, and SF~6~ emissions, refer to the U.S. Environmental
    Protection Agency's *Inventory of U.S. Greenhouse Gas Emissions and
    Sinks: 1990 -- 2003* (April 15, 2005), web site:
    yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterPublicationsGHGEmissions

    USEmissionsInventory2005.html.

[^139]: U.S. Environmental Protection Agency, Office of Atmospheric
    Programs, Climate Protection Partnerships Division, Climate Leaders
    Program, web site: www.epa.gov/climateleaders/.

[^140]: U.S. Environmental Protection Agency, "Climate Leaders
    Greenhouse Gas Inventory Protocol, Core Module Guidance \-- Direct
    HFC and PFC Emissions from Use of Refrigeration and Air Conditioning
    Units" (October 2004), Web site:
    www.epa.gov/climateleaders/docs/refrige_acequipuseguidance.pdf.

[^141]: Intergovernmental Panel on Climate Change, *IPCC Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories* (2000), web site:
    *www.ipcc-nggip.iges.or.jp/public/gp/english/*.

[^142]: .Intergovernmental Panel on Climate Change. *IPCC Good Practice
    Guidance and Uncertainty Management in National Greenhouse Gas
    Inventories*. (2000), web site:
    *[www.ipcc-nggip.iges.or.jp/public/gp/english/](http://www.ipcc-nggip.iges.or.jp/public/gp/english/).*

[^143]: This worksheet is available at web site
    [www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=OTAx&doOpen=1&ClickMenu=No](http://www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=OTAx&doOpen=1&ClickMenu=No).

[^144]: Those facilities should consult Part C, "Stationary Combustion."

[^145]: Transmission usually refers to the longer distance, higher
    capacity (e.g., higher voltage, greater steam throughput) travel.
    Distribution refers to lower capacity conveyance that allocates
    products to individual users. Throughout the remainder of this
    section, the term "transmission" will be used to refer collectively
    to the transmission and distribution of energy products.

[^146]: U.S. Energy Information Administration, *Emissions of Greenhouse
    Gas Emissions in the United States 2002* (2003), web site:
    www.eia.doe.gov/oiaf/1605/ggrpt/index.html.

[^147]: While the generation of electricity has been opened to market
    competition in many states, all public utilities are still regulated
    at some level, usually at the level of electricity transmission and
    distribution.

[^148]: It is not uncommon for facilities that operate cogeneration
    (i.e., CHP) plants to sell their electricity if they cannot use it
    on site. Facilities that purchase electricity from cogeneration
    plants should refer to the discussion on Electricity or Heat
    Supplied by a Combined Heat and Power Generator, below, in order to
    address the considerations particular to cogeneration.

[^149]: Method adopted from: World Business Council for Sustainable
    Development / World Resources Institute, *Working 9 to 5 on Climate
    Change: An Office Guide* (December 2002), web site:
    [www.safeclimate.org](http://www.safeclimate.org/) .

[^150]: This method for estimating energy consumption from purchased
    steam is derived from the California Climate Action Registry,
    *General Reporting Protocol* (October 2002), web site:
    www.climateregistry.org/PROTOCOLS/GRCP/.

[^151]: American Petroleum Institute, *Compendium of Greenhouse Gas
    Estimation Methodologies for the Oil and Gas Industry* (February
    2004) , web site:
    http://www.api.org/ehs/climate/new/upload/2004_COMPENDIUM.pdf
    (2001), web site: http://api-ec.api.org/policy

[^152]: Alternatively, reporters can refer to steam tables available
    on-line, including at the following web sites:

    www.engineeringtoolbox.com/28_457.html or

    www.efunda.com/materials/water/steamtable_sat.cfm.

[^153]: This method is adapted from the following sources:

    \- U.S. Environmental Protection Agency, *Climate Leaders Greenhouse
    Gas Inventory Protocol,* "Indirect Emissions from Purchases / Sales
    of Electricity and Steam" (October 20043June 2003),
    http://www.epa.gov/climateleaders/docs/indirectelectricityguidance.pdfhttp://www.e

    \- World Business Council for Sustainable Development / World
    Resources Institute, *Greenhouse Gas Protocol Initiative*, web site:
    http://www.ghgprotocol.org/plugins/GHGDOC/details.asp?type=DocDet&ObjectId=MTM3NTc.

    \- California Climate Action Registry, *General Reporting Protocol*
    (June 2006), web site: www.climateregistry.org/PROTOCOLS/GRCP/.

[^154]: This method is adapted from the following sources:

    \- U.S. Environmental Protection Agency, *Climate Leaders Greenhouse
    Gas Inventory Protocol,* "Indirect Emissions from Purchases / Sales
    of Electricity and Steam" (October 2004), web site:
    http://www.epa.gov/climateleaders/docs/indirectelectricityguidance.pdf

    October 2004
    http://epa.gov/climateleaders/docs/indirectelectricityguidance.pdf
    -World Business Council for Sustainable Development / World
    Resources Institute, *Greenhouse Gas Protocol Initiative* , web
    site:
    http://www.ghgprotocol.org/plugins/GHGDOC/details.asp?type=DocDet&ObjectId=MTM3NTc.

    -California Climate Action Registry, *General Reporting Protocol*
    (June 2006), web site: www.climateregistry.org/PROTOCOLS/GRCP/.

[^155]: Weighted average based on EIA\'s 1998 Manufacturers Energy
    Consumption Survey data on the quantities of natural gas, coal, and
    residual and distillate fuel oils consumed as boiler fuel, carbon
    coefficients provided in EIA\'s Assumptions to the Annual Energy
    Outlook 2003, and OIAF efficiency assumptions of 80, 81, and 82
    percent for natural gas, coal and petroleum boilers, respectively.

[^156]: For guidance on estimating the energy content of purchased steam
    or hot water, see the discussion under Section 1.F.2.5- Energy
    Consumption, above.

[^157]: This method is adapted from: California Climate Action Registry,
    *General Reporting Protocol* (October 2002), web site:
    www.climateregistry.org/PROTOCOLS/GRCP/.

[^158]: For guidance on estimating a transmission loss adjustment
    factor, see the discussion under the section on Chilled Water,
    above.

[^159]: Facilities that meet their electrical and thermal demands
    through on-site CHP generation should consult Part C for emission
    estimation methods.

[^160]: Plant operators may consider fuel consumption and other
    generation-related data proprietary information that they do not
    want to share. In these cases, reporters can ask their suppliers to
    estimate their emissions using the methods outlined in this chapter.

[^161]: Method taken from: Method adopted from: World Resources
    Institute, *WRI/WBCSD GHG Protocol Initiative Calculation Tool-
    Allocation of GHG Emissions from a Combined Heat and Power Plant*,
    *Version 1.0,* (September, 2006), website:
    http://www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=OTAx*Alloc*eptember
    2006), website:
    http://www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=OTAxU.S.
    Energy Information Administration. *Annual Energy Review
    2001*.(2002), p. 370, web site:
    http://tonto.eia.doe.gov/bookshelf/SearchResults.asp?title=Annual+Energy+Review.

[^162]: To convert electrical output to MMBtu, multiply electrical
    output in MWh by 3.412

[^163]: A discussion of current and potential sequestration strategies
    can be found in Carbon Sequestration Technology Roadmap and Program
    Plan, February 12, 2003, U.S. Department of Energy, Office of Fossil
    Energy, National Energy Technology Laboratory, web site
    www.netl.doe.gov/publications/carbon_seq/2005_roadmap_for_web.pdf.

[^164]: Naturally occurring CO~2~ is often harvested for use in enhanced
    oil recovery operations.

[^165]: In some commercially available gasification processes (e.g., the
    proprietary ChevronTexaco Gasification Process), a high-pressure
    stream of CO~2~ can be configured readily to be taken out of the
    shift reactor. At high pressure, this stream will require little
    compression for reinjection and storage.

[^166]: For more information on the FutureGen initiative, please visit
    the web site
    http://www.netl.doe.gov/technologies/coalpower/futuregen/.

[^167]: California Climate Action Registry. "California Climate Action
    Registry General Reporting Protocol." October 2002. Page 9-1.
    www.climateregistry.org/docs/PROTOCOLS/general_reporting_protocol_102102.pdf

[^168]: Based on Equations B-8, B-9 and B-10. American Petroleum
    Institute (API), *Compendium of Greenhouse Gas Emissions Estimation
    Methodologies for the Oil and Gas Industry, 2004*, web site:
    api-ec.api.org/filelibrary/ACF41C.pdf.

[^169]: Benson, S.M., Myer, L. *Monitoring to Ensure Safe and Effective
    Geologic Sequestration of Carbon Dioxide*. IPCC Workshop on Carbon
    Dioxide Capture and Storage.

[^170]: Livestock waste includes manure and urine.

[^171]: The percentage reported by IPCC 1997 is 1.25 percent, expressed
    as nitrogen (i.e., N~2~O-N); the factor of 2 percent converts to
    units of N~2~O using the molecular formula for N~2~O (e.g.,
    multiplies 1.25 percent by 44/28).

[^172]: The percentage reported by IPCC 1997 is 1.0 percent, expressed
    as nitrogen (i.e., N~2~O-N); the factor of 1.6 percent results from
    conversion to units of N~2~O using the molecular formula for N~2~O
    (e.g., multiplies 1.0 percent by 44/28).

[^173]: The percentage reported by IPCC 1997 is 2.5 percent, expressed
    as nitrogen (i.e., N~2~O-N); the factor of 4 percent results from
    conversion to units of N~2~O using the molecular formula for N~2~O
    (e.g., multiplies 1.0 percent by 44/28).

[^174]: Histosols are "Organic soils that have organic soil materials in
    more than half of the upper 80 cm, or that area of any thickness of
    overlying rock or fragmented materials that have interstices filled
    with organic soil materials." An organic soil material is defined
    as: "soil materials that are saturated with water and have 174 g/kg
    or more organic carbon if the mineral fraction has 500 g/kg or more
    clay, or 116 g/kg organic carbon if the mineral fraction has no
    clay, or has proportional intermediate contents, or if never
    saturated with water, have 203 g/kg or more organic carbon." (SSSA
    2001).

[^175]: See web site:
    www.wcc.nrcs.usda.gov/nutrient/nutrient-nitrogen.html.

[^176]: Burt, R. (ed.). 2004. *NRCS Soil Survey Laboratory Methods
    Manual* *Version 4*. USDA NRCS.

[^177]: The term "Base Value" has been used for the reference emissions
    level or emissions intensity against which the current-year
    emissions level or emissions intensity is compared in order to
    calculate an emission reduction. The WRI/WBCSD GHG Protocol uses the
    term "base year emissions" to differentiate entity-level reference
    emissions from "baseline emissions" as the latter is used in the
    context of project-based accounting under the Kyoto Protocol. The
    term "Base Value" is preferred here to the WRI/WBCSD terminology
    because it can be used generically to refer to an emissions level,
    an emissions-intensity level, or a benchmark. The term "reference
    case," which was used in the original 1605(b) program for
    base-period emissions, has not been used in the revised General
    Guidelines.

[^178]: For example, in 2007, an entity reporting but not registering
    reductions could conceivably submit a single-year base period report
    (in this case, this would also be the Start Year report) for 1990
    and then reports for 1991 and every year through 2006. Another
    entity registering reductionsports and not par??), submit a
    single-year base period report for 2005 (again, this would also be
    thet Year report) for 2005, and a Reporting Year report for 2006.

[^179]: Reporters may use annual estimates of carbon sequestration,
    rather than carbon stocks, to estimate reductions. In this case,
    reductions are the net of all annual fluxes in carbon stocks and are
    not compared to a base-period carbon sequestration.

[^180]: Economic metrics must be adjusted for inflation.

[^181]: Based on values recently adopted by the California Climate
    Action Plan\'s General Reporting Protocol (0.8 for natural
    gas-fueled absorption chillers and 1.2 for natural gas-fueled engine
    driven compressors), this value is 0.63 kg CO~2~/ton hour of
    cooling.

[^182]: U.S. Energy Information Administration, Instructions to Form
    EIA-1605, Appendix F, Draft, November 2006.

[^183]: International Energy Agency. *World Energy Outlook*, web site:
    www.worldenergyoutlook.org.

[^184]: See Table 1.C.5 for natural gas emission factors. Use an
    emission factor of 0.0529 metric tons/MMBtu if the higher heating
    value Btu content of the displaced natural gas is unknown.

[^185]: The reporting entity must use substantially the same
    organizational boundary to define the relevant transmission and
    distribution system when presenting calculations for both its based
    period and the current year.

[^186]: The calculation of net imports should include, but is not
    limited to, power received from and delivered to independent
    distribution companies that may be physically located within the
    footprint of the reporting entities transmission system.

[^187]: Include both electricity delivered directly to end users by the
    reporting entity and, to the extent not included in the calculation
    of "actual net interchange", power delivered to independent
    distribution companies physically located within the reporting
    entity's control area for delivery by such independent distribution
    companies to their end users.

[^188]: Actual net interchange is positive for power leaving the system
    and negative for power entering.

[^189]: U.S. Environmental Protection Agency, Background Document for
    Life-cycle Greenhouse Gas Emission Factors for Fly Ash Used as a
    Cement Replacement in Concrete, EPA530-R-03-016, November 7, 2003.

[^190]: U.S. Environmental Protection Agency, WAste Reduction Model
    (WARM), Version 6 (December 8, 2004),
    http://yosemite.epa.gov/oar/globalwarming.nsf/content/ActionsWasteWARM.html.

[^191]: U.S. Department of Transportation, Federal Highway
    Administration, Fly Ash Facts for Highway Engineers, June 13, 2003,
    FHWA-IF-03-019, Chapter 3,
    http://www.fhwa.dot.gov/Pavement/recycling/fach03.cfm.

[^192]: Intergovernmental Panel on Climate Change, *Climate Change 2001:
    The Scientific Basis*. (2001), Cambridge University Press, pp.
    390-391.

[^193]: Entities or subentities that have no emissions in the Base
    Period may use the avoided emission method to calculate emission
    reductions.

[^194]: Method adopted from: World Resources Institute, *WRI/WBCSD GHG
    Protocol Initiative Calculation Tool- Allocation of GHG Emissions
    from a Combined Heat and Power Plant*, *Version 1.0,* (September,
    2006), website:
    http://www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=OTAx

[^195]: In order to express electrical generation as MMBtu, multiply
    electrical output in MWh by 3.412