CDP Technical Note: Guidance methodology for
estimation of Scope 3 category 11 emissions for oil andgas companies
CDP Corporate QuestionnaireContents
Version ........................................................................................................................................... 4
Acknowledgements ......................................................................................................................... 5
Nomenclature and units .................................................................................................................. 6
1.

Introduction .............................................................................................................................. 7

2.

Boundaries .............................................................................................................................. 8
2.1 Organizational ....................................................................................................................... 8
2.2 Operational ............................................................................................................................ 8
2.3 Temporal ............................................................................................................................... 9
Figure 1: Value chain representation of company emissions .................................................... 93.

Industry and company structure ............................................................................................. 10
Figure 2: Sankey diagram illustrating aggregate material flows through oil and gas companies.............................................................................................................................................. 11

4. Relevance ................................................................................................................................. 13
Table 1: Criteria for identifying relevant Scope 3 activities [adapted from ref. 3, p.61] ............ 13
5. Methodology ............................................................................................................................. 15
5.1 Sales Method ...................................................................................................................... 15
5.1.1 Tier 1 ............................................................................................................................ 15
5.1.2 Higher Tier .................................................................................................................... 17
5.2 Production method .............................................................................................................. 18
5.2.1 Tier 1............................................................................................................................. 19
5.2.2 Higher Tier .................................................................................................................... 21
5.3 Throughput Method ............................................................................................................. 23
6. Disclosure ................................................................................................................................. 25
Table 2: Recommended items to include in ‘Emissions calculation methodology’ disclosure forquestion 7.8 ........................................................................................................................... 25
7. References ............................................................................................................................... 26
Appendix ....................................................................................................................................... 27
A1

Tier 1 defaults ................................................................................................................. 27

Table A-1: Default oil and gas product properties [11] (*Naphtha and LPG taken from [12-13],**NGL uses generic composition detailed in [14]) .................................................................. 27
A2

Effective oxidation rates .................................................................................................. 28

Table A-2: European and global non-energy use (NEU) fractions [15-17] .............................. 28
Table A-3: Global defaults of oxidation factors (OF), storage fractions (SF) and final effective
oxidation rate (EO) [18-19] ..................................................................................................... 29
A3Standard unit conversions............................................................................................... 30

Table A-4: Standard conversion tables for energy, mass, and volume ................................... 30
A4

Material flow comparison ................................................................................................ 31

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Figure A-1: Sankey diagrams comparing two aggregate material flows through oil and gas
companies ............................................................................................................................. 31
A5Worked example ............................................................................................................. 32

A6

Unit descriptions ............................................................................................................. 34

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Version
Version

Revision date

Revision summary

1.0
1.1

2018
April 6, 2020

1.2
2.0

January 7, 2021
January 21, 2022

2.1

January 9, 2023

2.2

June 28, 2024

First published version.
“Industry and company structure” section revised, and minor update to“Introduction” section to align with the 2020 CDP climate change
questionnaire.
Minor editorial changes
Additional guidance for companies responsible for the transportation(including maritime), storage, transmission, and distribution of fossil
fuels, including calculating scope 3 category 11 emissions based on
throughput.
Minor update to “Introduction” sector to update Scope 3 figures with
2021 CDP questionnaire analysis. Updates to figures in Appendix A toalign with a new version of the American Petroleum instituteCompendium.
Question numbers updated to align with the CDP Corporate
Questionnaire 2024

Copyright © CDP Worldwide 2024
All rights reserved. Copyright in this document is owned by CDP Worldwide, a registered charity number
1122330 and a company limited by guarantee, registered in England number 05013650.

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Acknowledgements
CDP would like to acknowledge Richard Heede of the Carbon Accountability Institute for his
advice and feedback from the beginning of and throughout the development of this document.
CDP is also appreciative of the feedback received from several oil and gas companies. The
guidance provided in this document does not necessarily reflect the views of industry
representatives.

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Nomenclature and units

A
AX
API
B
bbl
bcf
boe
boed
bpd
Btu
C
cf
EF
EFc
EFce
ES3.11
EO
F
FX
gal.
Gg
GJ
GR
GWP
HV
i
ii
iii
kg
m3
mbpd
mmbbl
mmcm
NEU
OF
P
p
S
SC
SF
SG
t
tCO2e
TJ
toe
X
Y
ρ

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Upstream sale
Upstream sale from own upstream production (X)American Petroleum Institute (gravity)
Downstream sale
Barrels
Billion cubic feet
Barrels of oil equivalent
Barrels of oil equivalent per day
Barrels per day
British thermal units
Carbon content
Cubic feet
Emission factor
Full combustion emission factor
Full combustion energy emission factor
Scope 3 category 11 emissions
Effective oxidation rate
Downstream feedstock
Downstream feedstock (F) from own upstream production(X)
Gallons (US)Giga-grams
GigajouleGas ratio (CO2e/CO2)
Global Warming Potential
Heating value
Upstream company (E&P) system boundary
Downstream company (refiner/processor) system boundary
Integrated company system boundary
Kilograms
Cubic meterThousand barrels per day
Million barrels
Million cubic meters
Non-energy use (portion of output for NEU)
Oxidation factor
Net production
Product
Sales
Sulfur content
NEU storage fraction
Specific gravity
Ton (metric ton)Tons of carbon dioxide equivalent
TerajouleTons of oil equivalent
Upstream net production
Downstream net production
Density@cdp | www.cdp.net

1. Introduction
Fossil fuel combustion releases carbon dioxide (CO2) and is the principal source of anthropogenic
greenhouse gas (GHG) emissions worldwide [1]. These emissions result primarily from the use ofcoal, oil and gas products. The WRI/WBCSD Greenhouse Gas Protocol [2] sets the standard forreporting direct company emissions (Scope 1), indirect emissions deriving from purchased energy
carriers (Scope 2), and value chain emissions (Scope 3). Scope 3 encompasses 15 distinct
categories covering all emissions along the corporate value chain. The use of sold products falls
under category 11 of Scope 3 and typically 1 represents 91%1 of total Scope 3 emissions 81% of
total Scope 1+2+3 emissions relating to oil and gas companies.
Company accountability for Scope 3 emissions is less obvious than for Scopes 1 or 2 and,without direct control over value chain activities, companies are less likely to estimate them as
accurately or as consistently. This document is a guide for standardizing the estimation of Scope
3 category 11 emissions from oil and gas companies. The methodology described herein willassist company analysts in improving the quality, transparency, and consistency of Scope 3
emissions reporting and disclosure to CDP.
Typically, a company will begin its GHG inventory by calculating its Scope 1 and 2 emissions;these direct and indirect emissions are not covered by this methodology. Similarly, guidance on
calculating emissions related to other Scope 3 categories has been excluded. Many oil and gas
producing companies have additional business activities in other industries, some of which may
also result in category 11 emissions. Company analysts are advised to consult GHG Protocol
guidance on Scope 3 reporting [3-4] for approaches to quantifying a company’s full emissions
inventory.
The GHG accounting questions in CDP’s Corporate Questionnaire are aligned with the GHG
Protocol. Corporate Scope 3 emissions should be reported under question 7.8. Column 1 “Scope
3 category” is directly related to the GHG Protocol Scope 3 categories.
Established under the GHG Protocol is a set of reporting principles: relevance, completeness,consistency, transparency, and accuracy [2, p.6]. These principles form the wider context within
which this methodology is applicable. The International Petroleum Industry Environmental
Conservation Association (IPIECA) also provides detailed guidance on emissions reporting for theoil and gas industry [5]. This guidance is acknowledged and should complement the proposed
methodology.

1 Based on analysis of 2021 company disclosures to CDPPage 7 of 36@cdp | www.cdp.net

2. Boundaries
The boundaries stated in this section are based on the reporting guidance of the GHG Protocol[2-4]. Where appropriate, they have been customized to reflect the characteristics of the oil and gas
industry.

2.1 Organizational
Organizational boundaries refer to assets that fall inside the company inventory boundary and theattribution of emissions from those assets to the company. Company operations are variable intheir legal and operational structures [2, p.16]. Company operations may be wholly owned,
incorporated or non-incorporated, joint ventures, subsidiaries, and so on. Consolidating GHG
emissions for corporate reporting has two separate approaches: equity share and control. Where acompany has joint ownership with a nation state, the same consolidation rules apply as withprivate/private partnerships. For the equity share approach, emissions are attributed according to
the share of equity the company has in an operation. Equity is measured by the company’s
economic interest in the operational asset, which is the company’s right to the asset’s risks andrewards. Typically, this share aligns with the company’s percentage ownership of the asset. Where
this is not the case, the economic substance of the relationship takes precedence over the legal
ownership form so that equity share reflects the economic interest [2]. The analyst preparing theemissions estimation may therefore need to consult the company’s accounting or legal staff toensure the appropriate equity share is applied.
For the control approach, emissions are fully attributed to the company that has control and are not
attributed if the company has an interest but no control. Control is defined as financial or
operational2. The definitions of control are detailed in the GHG Protocol [2, p.16-23] and,specifically for oil and gas companies, in IPIECA industry guidelines [5]. Whichever the applied
approach, the choice should be consistent throughout organizational levels and between partnerorganizations.

2.2 Operational
Operational boundaries refer to emission scopes and are categorized as direct or indirect relative
to the organizational boundary. Fifteen reporting categories of Scope 3 emissions are defined
under the GHG Protocol. These are represented in Figure 1 alongside Scope 1 and Scope 2 [3,p.31]. The six greenhouse gases agreed under the Kyoto Protocol are included.
Scope 1 emissions are direct GHG emissions from sources owned or controlled by the company.
Scope 2 emissions are indirect GHG emissions and derive from the generation of electricity,
steam, heating and cooling purchased by the company for its own consumption. Scope 3
emissions are all indirect GHG emissions other than those identified for Scope 2. Indirectemissions are from activities linked to the company but not owned or controlled by the company.
Scope 3 categories cover the full life cycle of a product’s emissions including steps before andafter the product’s position in the cycle.
Category 11 ‘use of sold products’ relates to direct use-phase emissions of sold products andservices over the expected product lifetime [3, p.48, 4, p.113]. GHG Protocol guidance on Scope 3
emissions reporting [3-4] identifies three general sources of category 11 emissions: those related
to a product’s direct energy demand; those occurring from the product’s use as a fuel or feedstock;and, those that relate to other forms of GHG emission during use. The products sold by oil and gas
companies are relevant only to the second of these three sources. The use-phase lasts until the

2 Operational control defines an organizational boundary and should not be confused with operationalboundaries, which are the subject of section 2.2.
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product is finally depleted, or disposed of, after which any further emission falls under category 12‘end-of-life treatment of sold products’.
Priority is given to category 11 because it typically represents over 90% of all GHG emissions(Scopes 1-3) relating to the oil and gas industry.

2.3 TemporalTemporal boundaries are defined here as relating to the period over which the company reports
emissions and the consideration of emissions over time. Companies disclose their emissions to
CDP on an annual basis and should specify their reporting period. Companies need only disclose
Scope 3 emissions for the reporting year.

Figure 1: Value chain representation of company emissions

It is acknowledged that the use of sales data in estimating Scope 3 category 11 emissions is open
to error because emissions result from product consumption and not product sale. The delay
between product sale and consumption varies but is not typically significant; therefore, thismethodology assumes that all sold oil and gas products are consumed, or ‘used’, in the same
reporting year. For a product used for non-energy purposes, total emissions may not occur initiallybut over the course of a prolonged lifetime. Category 11 includes emissions occurring in thepresent and in the future [3, p.33].

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3. Industry and company structureThis guidance applies to companies involved in the extraction and production of oil and gas(upstream), companies involved in the transport, handling, and storage of oil and gas and derived
products (midstream), companies involved in the refining/processing of oil and gas derived
products (downstream), and integrated companies involved in multiple areas of the oil and gas
value chain. All industry products recognized as conventional or unconventional are included.
Guidance for reporting Scope 3 category 11 emissions for companies with coal operations isprovided in a separate document.

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Figure 2: Sankey diagram illustrating aggregate material flows through oil and gas companies

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Aggregate material flows for these company types are depicted in Figure 2. Companies purely
involved in the transport, handling, and storage of oil and gas and derived products should basethe material flows in their operations on the throughput of products and consult section 5.3 forfurther details. Upstream companies are encompassed by system boundary (i), downstream
companies by system boundary (ii), and integrated companies by system boundary (iii). Each stepalong the process chain is marked by a narrow gap in the flow. At each step a product may beconsumed as fuel, used as feedstock, lost3, added to or taken from stocks, or traded with suppliersand consumers. The diagram excludes flows if they are external to the organizational boundary,as defined by the company, e.g. partner-company or royalty allocations. Upstream anddownstream sale4 of hydrocarbons is labelled A and B respectively. Upstream and downstream
production of hydrocarbons is labelled X and Y respectively. Use of own upstream production X as
feedstock is labelled FX, which should be deducted from the sum of X and Y in the calculation of
integrated company net production. Total feedstock to downstream processes is labelled F.
Equations (1-3) express the definition of net production (with reference to Figure 2) for eachcompany type. AX is upstream sale deriving from own upstream production X, and may besummed with Y as another approach to calculating integrated company net production.
Pi = X(1)

Pii = Y

(2)

Piii = Y + X – FX = Y + AX

(3)

Equations (4-6) define the limits of net production (with reference to Figure 2) for integrated
companies. In Figure 2 a dashed line indicates the maximum value of FX, where this maximum isequal to F when X > F (as in Figure 2) or is equal to X when X < F. In the former case, it is assumed
that no upstream purchases are used as feedstock to the company’s own downstream operations.
In the latter case5, it is assumed that upstream purchases are only used as feedstock forovercoming upstream production deficits. Conversely, the minimum value of FX occurs when only
upstream purchases are used as feedstock to downstream operations, in which case X contributes
exclusively to A and FX = 0. In this case, if the company’s upstream sales derive exclusively from its
own production, then X = A, and thus A may be substituted for X in Equation (6).

or,Piii (min) = Y + X – F[when X > F]

(4)

Piii (min) = Y[when X < F]

(5)

Piii (max) = Y + X(6)Equations (7-9) express the definition of sales (with reference to Figure 2) for each company type.
Sales, as defined here, can only represent material flows leaving a company’s organizationalboundary, in which case integrated company sale is the summation of upstream and downstreamsale.
Si = A + F(7)
Sii = B

(8)Siii = A + B(9)

3 Losses include controlled, e.g. venting and flaring, and accidental losses.
4 Sales must cross the organizational boundary; this excludes sales between company subsidiaries.
5 To view aggregate material flow for both conditions of X refer to section A4 of the Appendix.

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4. Relevance
GHG Protocol guidance on Scope 3 reporting [2-3] defines a set of criteria for identifying relevant
Scope 3 categories. As stated at the end of section 2.2, this guidance applies to the estimation of
category 11 emissions only; this focus is applied because of the size of these emissions
associated with the oil and gas industry. As shown in Table 1, this represents one in a set of
relevancy criteria.
Criteria

Description of activities

Size

Sector guidance

They contribute significantly to the company’s total anticipated Scope 3
Emissions
There are potential emissions reductions that could be undertaken or
influenced by the company
They contribute to the company’s risk exposure (e.g., climate change
related risks such as financial, regulatory, supply chain, product and technology,
compliance/litigation, and reputational risks)
They are deemed critical by key stakeholders (e.g., customers, suppliers,
investors or civil society)
They are outsourced activities previously performed in-house or activities
outsourced by the reporting company that are typically performed in-houseby other companies in the reporting company’s sector
They have been identified as significant by sector-specific guidanceSpending or revenue
analysis
Other

They are areas that require a high level of spending or generate a high levelof revenue (and are sometimes correlated with high GHG emissions)
They meet any additional criteria developed by the company or industry sector

Influence
Risk

Stakeholders
Outsourcing

Table 1: Criteria for identifying relevant Scope 3 activities [adapted from ref. 3, p.61]
It should be acknowledged that double counting between companies is an inherent characteristic of
Scope 3 emissions. This is because Scope 3 emissions occur outside of the company’sorganizational boundary and, thus, inside the boundary (Scope 1) of other emitting entities orcompanies. Double counting may also occur between categories within Scope 3; for example, if two
companies simultaneously account for third-party transportation of goods between them [3, p.108].
Viewing category 11 at the industry level, double counting would need to be avoided so as toaggregate to the industry total. However, industry level emissions accounting is not the purpose of
Scope 3 disclosure and would be more suitably estimated via the use of statistical datasets suchas those compiled by the International Energy Agency (IEA) and the US Energy Information
Administration (EIA).
Viewing category 11 at the company level, there should be no deductions from a company’s saleof products on the basis of double counting with another company. For example, a company
should not deduct the emissions of an upstream product if the product is used as feedstock for adifferent company’s downstream production. Within a single company’s inventory, however,double counting should be avoided. For example, a company should deduct the Scope 3
emissions related to an upstream product if the product is used as feedstock for its own
downstream production. Often, reported company sales volumes include transactions between
different subsidiaries of that company, therefore the material flow does not cross the organizational

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boundary. In this case the company should deduct internal sales from this ‘gross’ sales figure inorder to avoid double counting.
For E&P companies, refiners/processors, and integrated companies, comparing accountability for
product emissions is complex. This is because there is significant trading of products between
upstream and downstream production processes, intra- and inter-companies. An alternative
approach to comparing companies within this sample is to redefine category 11 activity data as
net production (as opposed to sales). This approach is relevant if accountability for emissions isdefined by a company’s direct involvement in the extraction of natural stores of carbon and theconversion of carbon into usable products.
As described in the previous section, a company’s net production (P) is defined as the total
production after deducting for losses, stock changes, and self-consumption. Self-consumption isdefined as the consumption by a company of its own production, i.e. as fuel or feedstock. For an
integrated company, total production includes production of both upstream and downstream
products.
As expressed in Equation (3), calculating net production of upstream and downstream products
requires data on the company’s consumption of its own upstream production as feedstock (FX) or
sale of its own upstream production (AX). If these data are difficult to obtain, the analyst may wish
to apply a minimum or maximum boundary, as in Equations (4-6). If the structure of an integrated
company is weighted to upstream production, then the analyst may wish to apply Equation (4). In
this case, Piii(min) ≈ X so the analyst may decide to simplify the approach and count only
upstream production. If the structure is weighted to downstream production, then the analyst may
wish to apply Equation (5), Piii (min) = Y. In either case, the analyst should acknowledge that these
simplifications equate to a minimum limit of Scope 3 category 11 emissions and could present a
misleading picture. For example, an E&P company and an upstream oriented integrated company
would be measured by the same activity regardless of additional downstream activity arising fromthe latter. And over time, if the integrated company’s upstream production decreases while
downstream (net of Fx) increases at a faster rate, then successive estimations would show Scope
3 emissions to be falling when they are in fact rising.
Accountability can also be complex for companies that handle O&G products without actuallyowning them (e.g. pipelines and storage, gas distribution networks). While O&G products are notdirectly sold by these companies, the emissions from their end use still generates Scope 3
emissions, that arise as “a consequence of an organization’s operations and activities, but thatarises from GHG sources that are not owned or controlled by the [reporting] organization.” [6].
Much like the O&G producers, these emissions can constitute significant and substantial
emissions [7]. Reporting scope 3 category 11 emissions for handled O&G products places thesecompanies on the same footing as the rest of the O&G value chain and resolves a fundamental
unfairness for the rest of the industry.

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5. Methodology
The estimation methodology builds on the tier approach established under the 2006 IPCC
Guidelines for National Greenhouse Gas Inventories [8]. The fundamental form of estimation
combines data on the extent to which a human activity takes place (activity data) with coefficientsthat quantify the emissions, or removals, per unit of activity (emission factors). This relationship isexpressed in Equation (10).
Emissions = Activity data • Emission factor(10)

The level of methodological complexity is represented by three tiers: tier 1 (basic), tier 2(intermediate), and tier 3 (advanced). Tier 1 is generally designed for the application of readily
available, or aggregate, company activity data with default emission factors, which are available,
for example, from IPCC default parameter tables [9, p.2. 16]. Tier 2 and tier 3 are designed for theuse of more granular activity data and emission factors and for a wider inclusion of processparameters. Tier 2 and tier 3 are referred to as higher tier methods.
This guidance distinguishes between tier 1 and higher tier estimation complexity. The company
analyst should choose estimation complexity based on the time and resources available. If
attempting higher tier estimation, the analyst should refer to sections on both tier 1 and higher tier.
Choice of activity data is dependent on the definition of what activities are deemed relevant to thecompany. As discussed in section 4, relevance is dependent on a set of key criteria and otherconsiderations specific to the industry. This guidance describes two distinct choices for activity
data which reflect two alternative views on relevancy. The first choice incorporates sales data
while the second choice incorporates production data.

5.1 Sales Method
A company may sell significantly different quantities of hydrocarbon product than it produces. In
such a case the analyst should consider GHG Protocol Guidance on activity relevancy (see section
4). If the sale of hydrocarbon products purchased from other companies is deemed relevant, thenthe analyst should apply the sales approach. Only sales that cross the organizational boundary
should be counted.
5.1.1 Tier 1
The tier 1 emissions calculation is expressed in Equations (11-12).
ES3.11 = ∑ Sp ∙ EFcp
p=1

or,

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ES3.11 = ∑ Sp ∙ HVp ∙ EFce
p
p=1

(11)

(12)

@cdp | www.cdp.net

Where6:
ES3.11
p
S
HV
EFc
EFce
Note:
a:

= Scope 3 category 11 GHG emissions, units: metric tons (t) of CO 2e= hydrocarbon product= quantity sold, units: t, mmbbl, mbpd, boe, boed, bcf, mmcm, etc.
= heating value, units: GJ/kg, TJ/Gg, toe/m3, boe/gal., Btu/cf, etc.
= full combustion emission factor, units: tCO2e/t, tCO2e/mcm, tCO2e/mmBtu, etc.
= full combustion energy emission factor, units: tCO2e/TJ, tCO2e/boe, etc.
Product totals shall be disaggregated, e.g. upstream into crude oil, natural gas, andnatural gas liquids; downstream into gasolines, kerosene, fuel oils, and other.

Upstream products include oil, natural gas, and natural gas liquids (NGLs) and should be
separated as such. Oil is more variable in its carbon content than natural gas or NGL so the analyst
should apply his or her own professional judgement as to its level of disaggregation, e.g. crude oil,bitumen, synthetic oil, shale oil, and oil sands, or to apply an average EF that is more
representative of the oil portfolio than the global average.
Downstream products should also be disaggregated. Product groupings already disclosed inannual filings may be chosen, e.g. gasolines, kerosene, fuel oils, and other. It is expected that thecompany analyst applies knowledge of those products labelled as other.
If the analyst is aware of a product that is unlikely to release all of its carbon within its lifetime, thenthe analyst may wish to adjust for this. For example, if asphalt is sold for road surfacing and othernon-energy use (NEU) applications, then the analyst may wish to exclude this product from theestimation. If data on product application is unavailable, then the analyst should apply his or her
own professional judgement.
Activity can be measured in units of mass, volume, or energy. If the analyst has activity data inphysical units (mass or volume) and uses energy emission factors (EFce), then Equation (12)should be adopted. If the analyst has volumetric activity data and mass emission factors, or viceversa, then the analyst should obtain and apply product density data before adopting Equation(11). The analyst should aim to match physical data units to minimize the number of steps in thecalculation.
Should the analyst only have ready access to production data, then this may be used as a proxyfor sales data based on the following conditions: the company is not integrated; production
excludes that which is consumed by the company; the analyst is aware of no other reason why
production would be significantly different from sales, e.g. product storage.
It is common for companies to analyze energy by higher heating value (HHV), as opposed tolower heating value (LHV)7. LHV is lower than HHV by the latent energy of vaporization of the waterproduct of combustion. For fossil fuel solids and liquids, the LHV/HHV ratio is typically 0.95, and forgases it is typically 0.9. The analyst should be consistent with the use of either HHV or LHV. For
example, if EFce represents an emission per LHV, then the analyst should use activity data in LHV
or convert activity data to LHV from HHV or physical unit.
The analyst should not use carbon dioxide (CO2)8 EFs as a proxy for greenhouse gas EFs. Whenused together, GHGs are measured in carbon dioxide equivalent (CO2e). Relevant GHGs include
6 For unit descriptions please refer to section A6 of the Appendix.
7 LHV may also be referred to as the net calorific value (NCV), and HHV the gross calorific value (GCV).
8 If necessary, carbon content (C) should be converted to CO2 using the molecular ratio (CO2 = 44/12 C).

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CO2, methane (CH4), and nitrous oxide (N2O). To convert from non-CO2 to CO2e, the analyst
should apply global warming potential (GWP) factors. GWP relates the radiative forcing of agreenhouse gas over a certain period of time to that of CO2. Where necessary, the analyst should
apply the 100-year GWPs published in the IPCC Fifth Assessment report [1, Table 8.7]; for CH4
and N2O these are 34 and 298 respectively.
5.1.2 Higher Tier
The higher tier emissions calculation is expressed in Equations (13-15).
ES3.11 = ∑ Sp ∙ EFcp ∙ EOp

(13)

p=1

or,

ES3.11 = ∑ Sp ∙ Cp ∙ 44⁄12 ∙ GRp ∙EOp

(14)

EOp =OFp ∙ (1- NEUp ) + NEUp ∙ (1- SFp )

(15)

p=1

where,
Where9:ES3.11
p
S
C
GR
EFc
EO
OF
NEU
SF
Note:
a:

b:
c:
d:

= Scope 3 category 11 GHG emissions, units: metric tons (t) of CO2e
= hydrocarbon product= quantity sold, units: t, mmbbl, mbpd, boe, boed, bcf, mmcm, etc.
= Carbon content= GHG gas ratio (CO2e/CO2)= full combustion emission factor, units: tCO2e/t, tCO2e/mcm, tCO2e/mmBtu, etc.
= effective oxidation rate
= oxidation factor= non-energy use fraction= storage factor
Product totals shall be disaggregated, e.g. upstream into oil (see note b), natural gas, andnatural gas liquids; downstream into motor gasoline, diesel, naphtha, fuel oil, residual fueloil, kerosene, and liquefied petroleum gas.
Oil shall be disaggregated or applied with a representative average emission factor.
Physical unit (mass or volume) of activity data and emission factors should match and theuse of heating values should be avoided.
Effective oxidation rate should be determined for each product or product category.

Upstream products include oil, natural gas, and natural gas liquids (NGLs) and should be
separated as such. Oil (heavy/medium/light crude oil, bitumen, synthetic oil, shale oil, oil sands,etc.) should be further disaggregated to distinguish between products of different carbon content.
The analyst may not use a global average, or default, emission factor for oil but must use
company data, e.g. oil assays.
Downstream products should also be disaggregated. The analyst should aim to disaggregate
activity data for downstream products in alignment with recognized product categories of theindustry. These are exemplified in Table A-1 of the Appendix.
The analyst should also take account of product oxidation. Imperfect combustion is accounted for

9 For unit descriptions refer to the Nomenclature

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by the product’s oxidation factor (OF), which is typically between 0.99 and 1. The OF is applied to
the non-NEU fraction of product p. Within the NEU fraction of product p, a portion of carbon isstored. This portion is accounted for by the product’s storage factor (SF). Taking these factors into
account, the analyst may estimate a product’s effective oxidation rate (EO). The EO is defined here
as the ultimate proportion of a product that is emitted over its lifetime. For an analysis of thesefactors, refer to section A2 of the Appendix.
The analyst shall not use production data as a proxy for sales data under any circumstances.
As with tier 1, the analyst should account for non-CO2 emissions and, where necessary, apply
GWPs of 34 and 298 for CH4 and N2O, respectively. Equation (14) introduces the gas ratio (GR),which is the ratio of product greenhouse gas to carbon dioxide (CO2e / CO2). For ease of
calculation, the gas ratio is used alongside data pertaining to carbon content only. The gas ratio
may also be used were information on CH4 or N2O data is difficult to obtain. Estimated GR values
can be found in Table A-1 of the Appendix.
When using EF data from literature, the analyst should match physical data units (mass orvolume) between activity data and emission factors. The analyst should avoid using heating values
and energy emission factors but apply raw physical data with physical emission factors.
For oil emission factors the analyst should use company data. Carbon content may be obtained
directly from chemical analyses or estimated from product API gravity and sulfur content. Chapter
2 of the IPCC publication “Good Practice Guidance and Uncertainty Management in National
Greenhouse Gas Inventories” [10] contains a method for estimating oil carbon content from API
gravity and sulfur content. The method is expressed in Equations (16-17), where C is carbon
content (%), SC is sulfur content (%), SG is specific gravity, API is the API gravity10 at 60 degrees
Fahrenheit.

C=76.99+10.19 ∙ SG - 0.76 ∙ SC

where,

SG=

141.5(API+131.5)

(16)

(17)

If necessary, the analyst may use API gravity to convert oil activity data from volume to mass. The
relationship between oil density and API is expressed in Equation (18), where ρ is density (t/bbl).

ρ =141.5 • 0.159
API + 131.5(18)

5.2 Production method11
A company may produce significantly different quantities of hydrocarbon product than it sells. In
such a case the analyst should consider GHG Protocol Guidance on activity relevancy (seesection 4). If the sale of hydrocarbon products purchased from other companies is deemed
irrelevant, then the analyst may wish to apply the production approach. There may exist otherpractical reasons as to why the production method is selected over sales, e.g. lack of traceability in
10 In 1921 the API scale replaced the Baumé scale, which should be avoided here.
11 This section is structured identically to section 5.1.

Page 18 of 36@cdp | www.cdp.net

volumetric sales intra- and inter-organizational boundaries.
5.2.1 Tier 1
The tier 1 emissions calculation is expressed in Equations (19-20).

ES3.11 = ∑ Pp ∙ EFcp
p=1

or,

Where12:
ES3.11
p
P
HV
EFc
EFce
Note:
a:

(19)

ES3.11 = ∑ Pp ∙ HVp ∙ EFce
p

(20)

p=1

= Scope 3 category 11 GHG emissions, units: metric tons (t) of CO2e
= hydrocarbon product= net production, units: t, mmbbl, mbpd, boe, boed, bcf, mmcm, etc.
= heating value, units: GJ/kg, TJ/Gg, toe/m3, boe/gal., Btu/cf, etc.
= full combustion emission factor, units: tCO2e/t, tCO2e/mcm, tCO2e/mmBtu, etc.
= full combustion energy emission factor, units: tCO2e/TJ, tCO2e/boe, etc.
Product totals shall be disaggregated, e.g. upstream into oil, natural gas, and natural gas
liquids; downstream into gasolines, kerosene, fuel oils, and other.

Upstream products include oil, natural gas, and natural gas liquids (NGLs) and should be
separated as such. Oil is more variable in its carbon content than natural gas or NGL so the analyst
should apply his or her own professional judgement as to its level of disaggregation, e.g. crude oil,bitumen, synthetic oil, shale oil, and oil sands, or to apply an average EF that is more
representative of the oil portfolio than the global average.
Downstream products should also be disaggregated. Product groupings already disclosed inannual filings may be chosen, e.g. gasolines, kerosene, fuel oils, and other. It is expected that thecompany analyst applies knowledge of those products labelled as other.
If the analyst is aware of a product that is unlikely to release all of its carbon within its lifetime,then the analyst may wish to adjust for this. For example, if asphalt is produced for road surfacing
and other non-energy use (NEU) applications, then the analyst may wish to exclude thisproduct from the estimation. If data on product application is unavailable, then the analyst should
apply his or her own professional judgement.
Activity can be measured in units of mass, volume, or energy. If the analyst has activity data inphysical units (mass or volume) and uses energy emission factors (EFce), then Equation (20)should be adopted. If the analyst has volumetric activity data and mass emission factors, or viceversa, then the analyst should obtain and apply product density data before adopting Equation(19). The analyst should aim to match physical data units so as to minimize the number of steps inthe calculation.
It is common for companies to analyze energy by higher heating value (HHV), as opposed tolower heating value (LHV)13. LHV is lower than HHV by the latent energy of vaporization of the
12 For unit descriptions please refer to section A6 of the Appendix.
13 LHV may also be referred to as the net calorific value (NCV), and HHV the gross calorific value (GCV).

Page 19 of 36@cdp | www.cdp.net

water product of combustion. For fossil fuel solids and liquids, the LHV/HHV ratio is typically 0.95,
and for gases it is typically 0.9. The analyst should be consistent with the use of either HHV or
LHV. For example, if EFce represents an emission per LHV, then the analyst should use activity
data in LHV or convert activity data to LHV from HHV or physical units.
The analyst should not use carbon dioxide (CO2)14 EFs as a proxy for greenhouse gas EFs. Whenused together, GHGs are measured in carbon dioxide equivalent (CO2e). Relevant GHGs include
CO2, methane (CH4), and nitrous oxide (N2O). To convert from non-CO2 to CO2e, the analyst
should apply global warming potential (GWP) factors. GWP relates the radiative forcing of agreenhouse gas over a certain period of time to that of CO2. Where necessary, the analyst should
apply the 100-year GWPs published in the IPCC Fifth Assessment report [1, Table 8.7]; for CH4
and N2O these are 34 and 298 respectively.

14 If necessary, carbon content (C) should be converted to CO

Page 20 of 36

2 using the molecular ratio (CO 2 = 44/12 C).

@cdp | www.cdp.net

5.2.2 Higher Tier
The higher tier emissions calculation is expressed in Equations (21-23).
ES3.11 = ∑ Pp ∙ EFcp ∙ EOp

(21)

p=1

or,

ES3.11 = ∑ Pp ∙ Cp ∙ 44⁄12 ∙ GRp ∙EOp

(22)

EOp =OFp ∙ (1- NEUp ) + NEUp ∙ (1- SFp )

(23)

p=1

where,

Where15:
ES3.11 = Scope 3 category 11 GHG emissions, units: metric tons (t) of CO2ep
= hydrocarbon productP= net production, units: t, mmbbl, mbpd, boe, boed, bcf, mmcm, etc.
C
= Carbon content
GR= GHG gas ratio (CO2e/CO2)EFc= full combustion emission factor, units: tCO2e/t, tCO2e/mcm, tCO2e/mmBtu, etc.
EO
= effective oxidation rateOF= oxidation factor
NEU = non-energy use fractionSF= storage factor
Note:a:
Product totals shall be disaggregated, e.g. upstream into oil (see note b), natural gas, andnatural gas liquids; downstream into motor gasoline, diesel, naphtha, fuel oil, residual fueloil, kerosene, and liquefied petroleum gas.
b:
Oil shall be disaggregated or applied with a representative average emission factor.
c:Physical unit (mass or volume) of activity data and emission factors should match and theuse of heating values should be avoided.
d:Effective oxidation rate should be determined for each product or product category.

Upstream products include oil, natural gas, and natural gas liquids (NGLs) and should be
separated as such. Oil (heavy/medium/light crude oil, bitumen, synthetic oil, shale oil, oil sands,etc.) should be further disaggregated to distinguish between products of different carbon content.
The analyst may not use a global average, or default, emission factor for oil but must use
company data, e.g. oil assays.
Downstream products should also be disaggregated. The analyst should aim to disaggregate
activity data for downstream products in alignment with recognized product categories of theindustry. These are exemplified in Table A-1 and of the Appendix.
The analyst should also take account of product oxidation. Imperfect combustion is accounted forby the product’s oxidation factor (OF), which is typically between 0.99 and 1. The OF is applied to
the non-NEU fraction of product p. Within the NEU fraction of product p, a portion of carbon isstored. This portion is accounted for by the product’s storage factor (SF). Taking these factors into
account, the analyst may estimate a product’s effective oxidation rate (EO). The EO is defined here
as the ultimate proportion of a product that is emitted over its lifetime. For an analysis of thesefactors, refer to section A2 of the Appendix.
15 For unit descriptions please refer to section A6

Page 21 of 36

of the Appendix.
@cdp | www.cdp.net

As with tier 1, the analyst should account for non-CO2 emission and, where necessary, apply
GWPs of 34 and 298 for CH4 and N2O, respectively. Equation (22) introduces the gas ratio (GR),which is the ratio of product greenhouse gas to carbon dioxide (CO2e / CO2). For ease of
calculation, the gas ratio is used alongside data pertaining to carbon content only. The gas ratio
may also be used were information on CH4 or N2O data is difficult to obtain. Estimated GR values
can be found in Table A-1 of the Appendix.
When using EF data from literature, the analyst should match physical data units (mass orvolume) between activity data and emission factors. The analyst should avoid using heating values
and energy emission factors but apply raw physical data with physical emission factors.
For oil emission factors the analyst should use company data. Carbon content may be obtained
directly from chemical analyses or estimated from product API gravity and sulfur content. Chapter
2 of the IPCC publication “Good Practice Guidance and Uncertainty Management in National
Greenhouse Gas Inventories” [10] contains a method for estimating oil carbon content from API
gravity and sulfur content. The method is expressed in Equations (18-19), where C is carbon
content (%), SC is sulfur content (%), SG is specific gravity, API is the API gravity16 at 60 degrees
Fahrenheit.
C=76.99+10.19 ∙ SG - 0.76 ∙ SC

where,

SG=

141.5(API+131.5)

(24)
(25)

If necessary, the analyst may use API gravity to convert oil activity data from volume to mass. The
relationship between oil density and API is expressed in Equation (26), where ρ is density (t/bbl).

ρ =141.5 • 0.159
API + 131.5(26)

16 In 1921 the API scale replaced the Baumé scale, which should be avoided here.

Page 22 of 36@cdp | www.cdp.net

5.3 Throughput Method
Companies which handle oil and gas products but do not own the products themselves should
calculate their Scope 3 category 11 emissions based on the throughput of these products through theiroperations. This represents the best way to capture the amount of product these companies have arole in processing, and thus the amount of product that they should report Scope 3 emissions for.
As discussed in section 4, integrated companies should avoid double counting within their inventory.
For example, any Scope 3 emissions for a transported product should be deducted if that product isused as a feedstock for downstream production. The Net Value Chain approach may be a useful
method to calculate volumes for integrated companies. See the SBTi guidance for further details(p.12-15).
The emissions calculation is expressed in Equations (27-28).

𝐸𝑆3.11 = ∑ 𝑇𝑝 ∗ 𝐸𝐹𝑝𝑐
𝑝=1

or,

(27)

𝐸𝑆3.11 = ∑ 𝑇𝑝 ∙ HVp ∙ EFce
p

(28)

𝑝=1

Where17:
ES3.11
p
T
HV
EFc
EFce
Note:
a:

= Scope 3 category 11 GHG emissions, units: metric tons (t) of CO 2e= hydrocarbon product= net throughput, units: t, mmbbl, mbpd, boe, boed, bcf, mmcm, etc.
= heating value, units: GJ/kg, TJ/Gg, toe/m3, boe/gal., Btu/cf, etc.
= full combustion emission factor, units: tCO2e/t, tCO2e/mcm, tCO2e/mmBtu, etc.
= full combustion energy emission factor, units: tCO2e/TJ, tCO2e/boe, etc.
Product totals shall be disaggregated, e.g. upstream into crude oil, natural gas, andnatural gas liquids; downstream into gasolines, kerosene, fuel oils, and other.

Upstream products include oil, natural gas, and natural gas liquids (NGLs) and should be separated
as such. Oil is more variable in its carbon content than natural gas or NGL so the analyst should apply
his or her own professional judgement as to its level of disaggregation, e.g. crude oil, bitumen,
synthetic oil, shale oil, and oil sands, or to apply an average EF that is more representative of the oil
portfolio than the global average.
Downstream products should also be disaggregated. Product groupings already disclosed in annual
filings may be chosen, e.g. gasolines, kerosene, fuel oils, and other. It is expected that the company
analyst applies knowledge of those products labelled as other.

17 For unit descriptions please refer to section A6 of the Appendix.

Page 23 of 36@cdp | www.cdp.net

If the analyst is aware of a product that is unlikely to release all of its carbon within its lifetime, then theanalyst may wish to adjust for this. For example, if asphalt for road surfacing and other non-energyuse (NEU) applications is included, then the analyst may wish to exclude this product from theestimation. If data on product application is unavailable, then the analyst should apply his or her own
professional judgement.
Activity can be measured in units of mass, volume, or energy. If the analyst has activity data inphysical units (mass or volume) and uses energy emission factors (EFce), then Equation (28) should
be adopted. If the analyst has volumetric activity data and mass emission factors, or vice versa, thenthe analyst should obtain and apply product density data before adopting Equation (27). The analyst
should aim to match physical data units to minimize the number of steps in the calculation.
It is common for companies to analyze energy by higher heating value (HHV), as opposed to lower
heating value (LHV). LHV is lower than HHV by the latent energy of vaporization of the water productof combustion. For fossil fuel solids and liquids, the LHV/HHV ratio is typically 0.95, and for gases it istypically 0.9. The analyst should be consistent with the use of either HHV or LHV. For example, if EFce
represents an emission per LHV, then the analyst should use activity data in LHV or convert activity
data to LHV from HHV or physical unit.
The analyst should not use carbon dioxide (CO2) EFs as a proxy for greenhouse gas EFs. When used
together, GHGs are measured in carbon dioxide equivalent (CO2e). Relevant GHGs include CO2,methane (CH4), and nitrous oxide (N2O). To convert from non-CO2 to CO2e, the analyst should apply
global warming potential (GWP) factors. GWP relates the radiative forcing of a greenhouse gas over acertain period of time to that of CO2. Where necessary, the analyst should apply the 100-year GWPs
published in the IPCC Fifth Assessment report [1, Table 8.7]; for CH4 and N2O these are 34 and 298
respectively.

Page 24 of 36@cdp | www.cdp.net

6. Disclosure
For general guidance on the disclosure of Scope 3 emissions to CDP, the reader is referred to
Module 7 of the CDP Corporate Questionnaire. The reporting company is required to disclose an
estimation of Scope 3 emissions in question 7.8 along with information on the methodology withwhich the figure was estimated. Table 2 details what an effective disclosure of category 11
estimation ‘Emissions calculation methodology’, table question column 3, should include.
Information

Description

Disclosure example

Methodologicalapproach

Direct reference to estimation method described in thisdocument:- ‘Sales method’- ‘Production method’- ‘Throughput method’
The reporter may also wish to state whether theestimation was tier 1 or higher tier. If the method used is
not one of the above methods, then the reporter should
state this and describe the adopted methodology ordifferences from the above.
Confirm whether or not all activity inside the organizationalboundary is included. Confirm if activity data is net ofroyalties. No activity inside the organizational boundary
should be excluded. [Note: the reporting company should
already have disclosed the boundary definition, e.g. equity
share, in question 6.1, and the estimation should apply
this boundary]Using the Production
method; Tier 1.

Coverage

Activity data

Product
information

Sources

Other

State activity data type: ‘net production’ or ‘sales’. The
reporter should state if production or sales differs in any
way to the definitions outlined in this document, or if proxy
data is used (with justification). The reporter may also
wish to refer directly Figure 2 by referencing the material
flows included.
State all products included and relevant calculation
information so that the estimation can be reproduced. This
includes the product name and amount produced/sold.
The reporter may also wish to include calculation
parameters: EF and, if used, LHV/HHV and oxidation rate
information. If the calculation parameters are taken
directly from literature, then the literature source may bereferenced instead. If company emission factors or activity
data are deemed sensitive information, then an
approximate or aggregated form of activity disclosure
enabling a rough reproduction of the estimation is
sufficient.
Reference the source(s) of activity data, emission factors,
and any other sources used, citing the references where
they are used or listing them at the end stating what they
were used for.

Not all activity inside
the organizationalboundary is included.
Only upstream
production is included.
The organizationalboundary is equity
share.
Activity data is net
production; P = X.

Products include:
Natural gas (505million cubic feet perday; 53 ktCO2e perbcf); Fuel oil…

Emission factors fromUS EPA 2014 –Emission Factors forGreenhouse gas
inventories.

Any other pertinent information.

Table 2: Recommended items to include in ‘Emissions calculation methodology’ disclosurefor question 7.8

Page 25 of 36@cdp | www.cdp.net

7. References
[1]

[2]

[3]

[4]

[5]
[6]
[7]
[8]
[9]
[10]
[11]
[12]
[13]
[14]
[15]
[16]
[17]
[18]

[19]

IPCC, 2013: Climate Change 2013: The Physical Science Basis. Contribution of Working
Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change[Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia,
V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, Cambridge, United Kingdom
and New York, NY, USA, 1535 pp.
WRI/WBCSD, ‘The Greenhouse Gas Protocol: A Corporate Accounting and ReportingStandard. Revised Edition’, World Business Council for Sustainable Development andWorld Resources Institute, Geneva and Washington DC, 2004.
WRI/WBCSD, ‘Greenhouse Gas Protocol: Corporate Value Chain (Scope 3) Accounting
and Reporting Standard’, World Business Council for Sustainable Development and World
Resources Institute, Geneva and Washington DC, 2011.
WRI/WBCSD, ‘Greenhouse Gas Protocol: Technical Guidance for Calculating Scope
3 Emissions’, World Business Council for Sustainable Development and World
Resources Institute, Geneva and Washington DC, 2013.
IPIECA, ‘Petroleum industry guidelines for reporting greenhouse gas emissions.
Second Edition’, IPIECA, London, 2011.
ACT, ‘ACT O&G methodology’, ACT, 2021
Flora, A., Wynn, G., ‘Hiding in Plain Sight—European Gas Pipeline Companies’
Greenhouse Gas Emissions’, IEEFA,
IPCC, ‘2006 IPCC Guidelines for National Greenhouse Gas Inventories. Volume 1:
General Guidance and Reporting’, IGES, Japan, 2006.
IPCC, ‘2006 IPCC Guidelines for National Greenhouse Gas Inventories. Volume 2:
Energy’, IGES, Japan, 2006.
IPCC, ‘Chapter 2 Energy’, ‘Good Practice Guidance and Uncertainty Management in
National Greenhouse Gas Inventories’, IGES, Japan, 2001.
API, ‘Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural
Gas Industry’, American Petroleum Institute, Washington DC, 2009.
AEA, ‘Annex 1 - Converting from fuel use to carbon dioxide equivalent emissions’,2012 Guidelines to Defra / DECC’s GHG Conversion Factors for Company. 2012.
AEA, ‘Annex 11 - Fuel Properties’, 2012 Guidelines to Defra / DECC’s GHG
Conversion Factors for Company Reporting. 2012.
BP, ‘NGL’, BP, 2014. [Online]. Available: http://www.bp.com/en_na/gas/northamerica/learn- more/ngl.html. [Accessed: 20-Oct-2015].
Eurostat, "Supply, transformation and consumption of gas - annual data," in (nrg_103a), 2015.
Eurostat, "Supply, transformation and consumption of oil - annual data," in (nrg_102a), 2015.
IEA, ‘2015 Key World Energy Statistics,’ OECD/IEA, Paris, 2015.
UNFCCC, ‘Table 1.A(b) Sectoral Background Data for Energy: CO2 from Fuel
Combustion Activities - Reference Approach’, National Inventory Submissions 2014:
Common Reporting Format. 2014.
UNFCCC, ‘Table 1.A(d) Sectoral Background Data for Energy: Feedstocks and NonEnergy Use of Fuels’, National Inventory Submissions 2014: Common Reporting Format.
2014.

Page 26 of 36@cdp | www.cdp.net

Appendix
A1

Tier 1 defaults

Fuel

API
(60°F)

Acetylene

ρ,
3
kg/m

HHV,GJ HHV,
/m3
GJ/t

LHV
/
HHV

%C

GR,
CO2e
/CO2

EFc,
EFc,
tCO2e tCO2e
/t
/m3

1.10

0.0549

49.9

0.91

92.3

1.0012

3.39 3.73e-3

Asphalt and Road Oil

5.6

1032

44.0

42.6

0.95

83.5

1.0036

3.07

3.17

Aviation Gas

69.0

706

33.5

47.5

0.95

85.0

Butane (liquid)

111.3

583

28.7

49.2

0.95

82.8

1.00401.0043

3.13
3.05

2.21
1.78

Crude Oil

30.5

873

38.5

44.1

0.95

84.8

1.0037

3.12

2.73

Distillate Oil (Diesel)

35.5

847

38.7

45.7

0.95

86.3

1.00373.18

2.69

Ethane (liquid)

248.3

373

19.4

52.1

0.95

80.0

1.0047

2.95

1.10

Fuel Oil #4

24.1

909

39.9

43.9

0.95

86.4

1.0038

3.18

2.89

3.05

1.71

Isobutane

120.5

562

27.6

49.1

0.95

82.8

1.0043

Jet Fuel

42.0

816

37.6

46.1

0.95

86.3

1.00393.18

2.59

Kerosene

41.4

818

37.6

45.9

0.95

86.0

1.0037

3.17

2.59

LPG*
Lubricants

139.4
25.6

522
901

25.7
40.2

49.2
44.6

0.95
0.95

79.9
85.8

1.00482.93

1.53

1.00393.16

2.84

Miscellaneous Product

30.5

873

38.5

44.1

0.95

85.5

1.00363.15

2.75

Motor Gasoline

59.1

742

34.9

47.0

0.95

86.6

Naphtha*

77.1

678

32.4

47.8

0.95

85.4

1.0042
1.0047

3.19
2.95

2.37
1.10

Natural Gas (processed)

-

0.67

0.0380

56.5

0.90

76.0

1.00122.79 1.88e-3

Natural Gas (raw)Natural Gas
Liquids (NGLs)**
Natural Gasoline
Pentanes Plus

-

0.67

0.0460

56.5

0.90

76.0

1.00122.79 1.88e-3

164.0
81.7
81.7

479
664
664

23.9
30.7
30.7

50.4
46.3
46.3

0.95
0.95
0.95

81.4
83.7
83.7

1.00441.0044

3.00
3.08

1.61
2.05

1.00423.08

2.05

PetrochemicalFeedstocks
Petroleum Coke

67.1

712

34.8

48.8

0.95

84.1

1.0040

3.10

2.21

35.0

850

40.0

47.1

0.95

92.3

Petroleum Waxes

43.3

810

36.7

45.3

0.95

85.3

1.00281.0039

3.39
3.14

0.00
2.54

1.90

0.0937

49.3

0.92

81.8

1.00053.00

5.7e-3

Propane (gas)Propane (liquid)

148.4

506

25.4

50.2

0.95

81.8

1.00423.01

1.52

Residual Oil #5

17.4

950

41.8

44.0

0.95

88.7

1.0037

3.26

3.10

Residual Oil #6

11.0

993

41.7

42.0

0.95

85.7

1.0037

3.15

3.13

0.95

84.8

1.0041

3.12

2.42

0.95

-

1.0043

-

-

0.95

85.5

1.0037

3.15

2.75

Special Naphtha

51.2

774

Still Gas
Unfinished Oils

34.8

44.9

39.8
30.5

873

38.7

44.3

Table A-1: Default oil and gas product properties [11] (*Naphtha and LPG taken from [12-13],**NGL uses generic composition detailed in [14])Page 27 of 36@cdp | www.cdp.net

A2

Effective oxidation rates

Fuel

Aviation gasoline
BitumenEthaneResidual Fuel Oil
Gas / Diesel Oil
Gasoline
Jet Kerosene
Liquefied Petroleum Gas (LPG)
Lubricants
NaphthaOther Kerosene
Other petroleum
Petroleum Coke
Petroleum product (wt. average)
Natural Gas Liquids
Oil
Plastics
Natural Gas

2013 NEU fraction - EU 28

2013 NEU fraction Global

0.0%
100.0%
100.0%
19.7%
0.8%
0.3%
0.0%
39.6%
100.0%
95.9%
6.8%
94.0%
16.4%
15.8%

0.0%
100.0%
100.0%
20.4%
0.9%
0.4%
0.0%
44.4%
100.0%
95.9%
8.2%
94.1%
16.4%
17.9%

Assumed as petroleum average
Assumed as petroleum average
100%
3%

100%
3%

Table A-2: European and global non-energy use (NEU) fractions [15-17]
Non-energy use fractions of total final consumption were calculated for the EU 28 from detailedenergy balances accessed through the Eurostat database [15-16]. Data on NEU consumption is
also available from this source at the sectoral level: Industry, Transport, and Other. To adjust for
global NEU fractions, EU 28 fractions were reallocated for the global sector energy split. In 2013an average of 72% of industrial petroleum product consumption was NEU, compared with just 1%
in each of the other sectors. Assuming these sector fractions, industry has a 24% share of total
final energy consumption at the global level, but a 21% share at the European level. Hence NEU
fractions from the EU level have been adjusted upwards for the global level.

Page 28 of 36@cdp | www.cdp.net

Fuel

OF

SF

EO

Aviation gasoline

0.993

-

99.3%

Bitumen

0.988

0.998

0.2%

Ethane

1.000

0.634

36.6%

Residual Fuel Oil

0.988

0.618

86.8%

Gas / Diesel Oil

0.994

0.618

98.9%

Gasoline

0.994

0.767

99.1%

Jet Kerosene

0.997

0.500

99.7%

Liquefied Petroleum Gas (LPG)

0.994

0.740

70.3%

Lubricants

0.996

0.446

55.4%

Naphtha

0.998

0.774

25.8%

Natural Gas Liquids

0.999

0.777

87.7%

Other Kerosene

0.994

0.915

93.2%

Other petroleum

0.992

0.758

28.7%

Petroleum Coke

0.997

0.859

85.7%

Petroleum product (wt. average)

0.994

0.723

88.1%

Natural Gas Liquids

Assumed as petroleum average

Oil

Assumed as petroleum average

Plastics

0.994

0.800

0.0%

Natural Gas

0.997

0.669

97.7%

Table A-3: Global defaults of oxidation factors (OF), storage fractions (SF) and final effective
oxidation rate (EO) [18-19]

Page 29 of 36@cdp | www.cdp.net

A3

Standard unit conversions

Energy conversion
unit per:Million Btu

GJ

toe

tce

kWh

kcal

Million Btu
GJ
toe
tce
kWh
kcal

1.000E+00
1.055E+00
2.520E-02
3.600E-02
2.931E+02
2.520E+05

9.478E-01
1.000E+00
2.388E-02
3.412E-02
2.778E+02
2.388E+05

3.968E+01
4.187E+01
1.000E+00
1.429E+00
1.163E+04
1.000E+07

2.778E+01
2.931E+01
7.000E-01
1.000E+00
8.141E+03
7.000E+06

3.412E-03
3.600E-03
8.598E-05
1.228E-04
1.000E+00
8.598E+02

3.968E-06
4.187E-06
1.000E-07
1.429E-07
1.163E-03
1.000E+00

Mass conversion
unit per:Short Tons

Kilograms

Metric Tons

Long Tons

PoundsShort Tons
Kilograms
Metric Tons
Long Tons
Pounds1.000E+00
9.072E+02
9.072E-01
8.929E-01
2.000E+03

1.102E-03
1.000E+00
1.000E-03
9.842E-04
2.205E+00

1.102E+00
1.000E+03
1.000E+00
9.842E-01
2.205E+03

1.120E+00
1.016E+03
1.016E+00
1.000E+00
2.240E+03

5.000E-04
4.536E-01
4.536E-04
4.464E-04
1.000E+00

Cubic
meters6.290E+00
2.642E+02
1.000E+03
3.531E+01
1.000E+00

Volume conversion
unit per:Barrels

U.S. gallons

LitersCubic feet

Barrels
U.S. gallons
LitersCubic feet
Cubic meters1.000E+00
4.200E+01
1.590E+02
5.615E+00
1.590E-01

2.381E-02
1.000E+00
3.785E+00
1.337E-01
3.790E-03

6.290E-03
2.642E-01
1.000E+00
3.531E-02
1.000E-03

1.781E-01
7.480E+00
2.832E+01
1.000E+00
2.832E-02

Table A-4: Standard conversion tables for energy, mass, and volume

Page 30 of 36@cdp | www.cdp.net

A4

Material flow comparison

Figure A-1: Sankey diagrams comparing two aggregate material flows through oil and gas
companies

Page 31 of 36@cdp | www.cdp.net

A5

Worked example

The worked examples shown in the box below demonstrate a high variability in the results of different
approaches for estimating Scope 3 category 11 emissions. This is why it is important that the reporting
company is explicit about the method and boundaries chosen in their estimation.
Tier 1 Production method – Total net production (P = X + Y – FX)
In 2015, company A had upstream production of 1,000 thousand barrels per day (mbpd) of crude oil,
200 mbpd of natural gas liquids, and 150 million cubic feet per day (mmcfpd) of natural gas. Refinery
production was: 50 mbpd of LPG, 600 mbpd of motor gasoline, 200 mbpd of diesel, 150 mbpd of fueloil, 60 mbpd ethane, 30 mbpd naphtha, and 30 mbpd of asphalts. Of crude oil and NGL production,
56% and 38% are used as feedstock in company owned refineries. The analyst believes that 100% ofasphalts are used for road surfacing and about 50% of naphtha and ethane is ultimately stored inplastic. The analyst is aware that company crude oil is largely of a medium grade, and therefore
reasonably represented by the global average EF. The data source has liquid EFs with units
kgCO2e/gallon (US), gas EFs with units of kgCO2e/cf. Note that each production figure is net of losses,
stock changes and self-consumption for energy.
Unit conversion
1 gallon = 1 mbpd × 42 × 103 × 365 = 15.33×106
1 cf = 1 mmcfpd × 106 × 365 = 365×106
Calculate emissions
1,000 mbpd × (1 – 0.56) × 15.33×106 × 10.32 kgCO2e/gallon

Oil
NGL

+

200 mbpd × (1 – 0.38) × 15.33×106 × 5.41 kgCO2e/gallon

Gas+

150 mmcfpd × 365×106 × 0.0545 kgCO2e/cf

LPG+

50 mbpd × 15.33×106 × 5.70 kgCO2e/gallon

Gasoline+

600 mbpd × 15.33×106 × 8.82 kgCO2e/gallon

Diesel+200 mbpd × 15.33×106 × 10.22 kgCO2e/gallon

Fuel oil+

150 mbpd × 15.33×106 × 11.00 kgCO2e/gallon

Ethane+60 mbpd × 50% × 15.33×106 × 4.07 kgCO2e/gallon

Naphtha+30 mbpd × 50% × 15.33×106 × 8.54 kgCO2e/gallon=

228.83×109kgCO2e

Answer should be reported in metric tons (tons) of CO2e with no commas: 228830000

Page 32 of 36@cdp | www.cdp.net

Tier 1 Production method – Simplified production (P = X)
Assuming a conversion rate of 5,800 cf per barrel of oil equivalent (boe), Company A has upstream
production of 756 mmboe and downstream production of 409 mmboe. Company A is therefore an
upstream oriented integrated company. A simplified approach to the production method would be to
assume that upstream production is representative of overall net production. In which case theprevious calculation is as follows:
Calculate emissions
1,000 mbpd × 15.33×106 × 10.32 kgCO2e/gallon

Oil
NGL

+

200 mbpd × 15.33×106 × 5.41 kgCO2e/gallon

Gas+

150 mmcfpd × 365×106 × 0.0545 kgCO2e/cf=

177.83×109kgCO2e

Answer should be reported in metric tons (tons) of CO2e with no commas: 177830000 Tier
1 Sales method (S = A + B)
Company A product sales partially derive from own production. This is reflected in the figures used forthe sales method calculation. Note that sales figures exclude sales that do not cross the organizationalboundary.
485 mbpd × 15.33×106 × 10.32 kgCO2e/gallon

Oil
NGL

+

208 mbpd × 15.33×106 × 5.41 kgCO2e/gallon

Gas+

152 mmcfpd × 365×106 × 0.0545 kgCO2e/cf

LPG+

80 mbpd × 15.33×106 × 5.70 kgCO2e/gallon

Gasoline+

840 mbpd × 15.33×106 × 8.82 kgCO2e/gallon

Diesel+300 mbpd × 15.33×106 × 10.22 kgCO2e/gallon

Fuel oil+

290 mbpd × 15.33×106 × 11.00 kgCO2e/gallon

Ethane+70 mbpd × 50% × 15.33×106 × 4.07 kgCO2e/gallon

Naphtha+41 mbpd × 50% × 15.33×106 × 8.54 kgCO2e/gallon=

318.33kgCO2e

Answer should be reported in metric tons (tons) of CO2e with no commas: 318330000

Page 33 of 36@cdp | www.cdp.net

A6

Unit descriptions
Description

Unit
Volume:barrels
thousand barrels
million barrels
billion barrels
trillion barrels
barrels per day
thousand barrels per day
million barrels per day
billion barrels per day
cubic feetthousand cubic feetmillion cubic feetbillion cubic feettrillion cubic feetcubic feet per day
thousand cubic feet per day
million cubic feet per day
billion cubic feet per day
gallons
thousand gallons
million gallons
billion gallons
trillion gallons
cubic meters
thousand cubic meters
million cubic meters
billion cubic meters
trillion cubic meters
cubic meters per day
thousand cubic meters per day
million cubic meters per day
billion cubic meters per day
litersthousand liters
million liters
billion liters
trillion liters
liters per day
thousand liters per day
million liters per day
billion liters per day

Page 34 of 36

bbl
mbbl
mmbbl
Bbbl
Tbbl
bpd
mbpd
mmbpd
Bbpd
cf
mcf
mmcf
Bcf
Tcf
cfpd
mcfpd
mmcfpd
Bcfpd
gal.
mgal.
mmgal.
Bgal.
Tgal.
cm
mcm
mmcm
Bcm
Tcm
cmpd
kcmpd
Mcmpd
Bcmpd
l
kl
Ml
Bl
Tl
lpd
mlpd
mmlpd
Blpd

@cdp | www.cdp.net

Description

Unit
Mass:

tons
kilo-tons
mega-tons
giga-tons
terra-tons
peta-tons
kilo-grams
mega-grams
giga-grams
tera-grams
peta-gramexa-gram
tons, shortkilo-tons, shortmega-tons, shortgiga-tons, shortterra-tons, shortpeta-tons, shorttons, longkilo-tons, longmega-tons, longgiga-tons, longterra-tons, long
peta-tons, longpoundskilo-pounds
mega-pounds
giga-pounds
terra-pounds
peta-pounds

t
kt
Mt
Gt
Tt
Pt
kg
Mg
Gg
Tg
Pg
Eg
ts
kts
Mts
Gts
Tts
Pts
tl
ktl
Mtl
Gtl
Ttl
Ptl
lb
klb
Mlb
Glb
Tlb
Plb
Energy:British thermal units
thousand British thermal units
million British thermal units
billion British thermal units
trillion British thermal units
peta-British thermal units
kilo-joules
mega-joules
giga-joules
tera-joules
peta-joules
exa-joules

Page 35 of 36

Btu
mBtu
mmBtu
Bbtu
TBtu
Pbtu
kJ
MJ
GJ
TJ
PJ
EJ

@cdp | www.cdp.net

Page 36 of 36

Description

Unitbarrels of oil equivalent
thousand barrels of oil equivalentmillion barrels of oil equivalentbillion barrels of oil equivalent
trillion barrels of oil equivalentbarrels of oil equivalent per day
thousand barrels of oil equivalent per day
million barrels of oil equivalent per day
billion barrels of oil equivalent per day
trillion barrels of oil equivalent per day
tons of oil equivalentkilo-tons of oil equivalentmega-tons of oil equivalentgiga-tons of oil equivalentkilo-calories
mega-calories
giga-calories
terra-calories
peta-calories
exa-calories
kilo-Watt-hours
mega-Watt-hours
giga-Watt-hours
tera-Watt-hours
peta-Watt-hours
tons of coal equivalentkilo-tons of coal equivalentmega-tons of coal equivalentgiga-tons of coal equivalent

boe
mboe
mmboe
Bboe
Tboe
boed
mboed
mmboed
Bboed
Tboed
toe
ktoe
Mtoe
Gtoe
kcal
Mcal
Gcal
Tcal
Pcal
Ecal
kWh
MWh
GWh
TWh
PWh
tce
ktce
Mtce
Gtce

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