ECONOMIC IMPACTS OF VALUE-ADDED OIL AND GAS PRODUCTS

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Canadian Energy Research Institute

ECONOMIC

IMPACTS OF

VALUE-ADDED

OIL AND GAS

PRODUCTS

STUDY NO. 188JULY 2020

ECONOMIC IMPACTS OF VALUE-ADDED OIL AND GAS PRODUCTS

Economic Impacts Of Value-added Oil and Gas Products

Authors: Evar Umeozor, Eranda Bartholameuz, Mohamed Refaei, Madie Zamzadeh, Jose Armas

Recommended Citation (Author-date style):

Evar Umeozor, Eranda Bartholameuz, Mohamed Refaei, Madie Zamzadeh, Jose Armas. 2020. “Economic

Impacts of Value-added Oil and Gas Products.” Study No. 188. Calgary, AB: Canadian Energy Research

Institute. https://ceri.ca/assets/files/Study 188 Full Report.pdf

Recommended Citation (Numbered style):

E. Umeozor, E. Bartholameuz, M. Refaei, M. Refaei, J. Armas. 2020. “Economic Impacts of Value-added Oil

and Gas Products.” Study No. 188. Calgary, AB: Canadian Energy Research Institute.

https://ceri.ca/assets/files/Study 188 Full Report.pdf

Copyright © Canadian Energy Research Institute, 2020

Sections of this study may be reproduced in magazines and newspapers with acknowledgment to the

Canadian Energy Research Institute

July 2020

Printed in Canada

Acknowledgements:

The authors of this report would like to extend their thanks and sincere gratitude to all CERI staff involved

in the production and editing of the material. Contributions from the following expert reviewers are also

appreciated:

Pietro Di Zanno, Di Zanno and Associates

David Tulk, Goobie Tulk Inc.

Prof. Ian Gates, University of Calgary

Dr. Experience Nduagu, ExxonMobil

ABOUT THE CANADIAN ENERGY RESEARCH INSTITUTE

Founded in 1975, the Canadian Energy Research Institute (CERI) is an independent, registered charitable

organization specializing in the analysis of energy economics and related environmental policy issues in

the energy production, transportation, and consumption sectors. Our mission is to provide relevant,

independent, and objective economic research of energy and environmental issues to benefit business,

government, academia, and the public.

For more information about CERI, visit www.ceri.ca

CANADIAN ENERGY RESEARCH INSTITUTE

150, 3512 – 33 Street NW

Calgary, Alberta T2L 2A6

Email: [email protected]

Phone: 403-282-1231

July 2020

Economic Impacts of Value-Added Oil and Gas Products iii

Table of Contents List of Figures ................................................................................................................................................ v

List of Tables ............................................................................................................................................... vii

Acronyms and Abbreviations ....................................................................................................................... ix

Executive Summary ...................................................................................................................................... xi

Price Competitiveness of Products .......................................................................................................... xi

Product Supply Scenarios ....................................................................................................................... xiv

Chapter 1: Introduction .......................................................................................................................... 1

Background ............................................................................................................................................... 1

Ongoing investment challenges and access to market issues .................................................................. 2

The role of diversification and growth of petrochemicals production..................................................... 2

Why Canada should invest in value-added products ............................................................................... 4

Focus of the Study .................................................................................................................................... 6

Chapter 2: Overview of Petrochemical Market Outlook ........................................................................ 9

Oil and Gas Petrochemical Feedstocks ..................................................................................................... 9

Feedstocks for Methanol Production ................................................................................................. 10

Feedstock for Ammonia Production .................................................................................................. 10

Feedstock for Ethylene and Propylene Production ............................................................................ 11

Feedstocks Supply Demand Outlook ...................................................................................................... 13

World Feedstock Outlook................................................................................................................... 13

Naphtha Supply Demand Outlook ..................................................................................................... 13

Natural Gas Supply Demand Outlook ................................................................................................ 15

Provincial Feedstock Overview .......................................................................................................... 17

Supply Demand and Market Outlooks for Petrochemicals .................................................................... 18

Supply and Demand Outlook ............................................................................................................. 18

Petrochemical Market Outlook .......................................................................................................... 21

Opportunities for Canada at Destination Markets ............................................................................. 26

Chapter 3: Methodology ............................................................................................................................. 31

Modelling Framework ............................................................................................................................ 31

Feedstock Demand and Product Supply Scenarios ................................................................................ 32

General Modelling Assumptions: ........................................................................................................... 33

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Chapter 4: Results and Discussion .............................................................................................................. 35

Supply Cost and Cash Cost of Products .................................................................................................. 35

Cumulative Cashflow and Payback Period ............................................................................................. 39

Macroeconomic Impacts of Investment ................................................................................................. 42

National GDP Impacts ........................................................................................................................ 42

Tax Revenue Impacts ......................................................................................................................... 43

Employment and Compensation Impacts .......................................................................................... 44

Regional Price Competitiveness of Products .......................................................................................... 45

Effect of Carbon Tax on Canadian Supply and Cash Costs ..................................................................... 49

Product Supply Scenarios and Economic Impacts .................................................................................. 50

Chapter 5: Conclusions ............................................................................................................................... 55

Bibliography ................................................................................................................................................ 58

Appendix A: Economic Modelling ............................................................................................................... 64

Appendix B: Process Modelling ................................................................................................................... 66

Appendix C: Input-Output Models .............................................................................................................. 68

Appendix D: Supply forecast and feedstock Requirement Data ................................................................. 70

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Economic Impacts of Value-Added Oil and Gas Products v

List of Figures Figure E.1: Comparison of 2019 Regional Prices of

Methanol to the Estimated RBC and CBC Breakeven Prices ..................................................... xii

Figure E.2: Comparison of 2019 Regional Prices of

Ammonia to the Estimated RBC and CBC Breakeven Prices .....................................................xiii

Figure E.3: Comparison of 2019 Regional Prices of

Ethylene to the Estimated RBC and CBC Breakeven Prices ......................................................xiii

Figure E.4: Comparison of Regional Prices of

Propylene to the Estimated RBC and CBC Breakeven Prices .................................................... xiv

Figure 1.1: Distribution of Oil Demand in the OECD in 2017 by Sector ........................................................ 3

Figure 1.2: Value of Chemical Sales Worldwide in 2018 ............................................................................... 5

Figure 2.1. World Petrochemical Feedstock Consumption .......................................................................... 9

Figure 2.2: Global Methanol Feedstock Breakdown ................................................................................... 10

Figure 2.3: Global Ammonia Feedstock Breakdown ................................................................................... 11

Figure 2.4: Ethylene and Propylene Output for Different Feedstocks........................................................ 12

Figure 2.5: Regional Ethylene and Propylene Feedstock Breakdown ........................................................ 12

Figure 2.6: The World Petrochemical Feedstock and End Products Outlook ............................................. 13

Figure 2.7: Refinery Capacity of Canadian Provinces.................................................................................. 14

Figure 2.8: Canada Crude Oil Production Forecast ..................................................................................... 15

Figure 2.9: Total Canadian Natural Gas Production .................................................................................... 16

Figure 2.10: Natural Gas Usage by Sector ................................................................................................... 17

Figure 2.11: Capacities of Methanol Derivatives Between 2015-2019....................................................... 19

Figure 2.12: World Ammonia Production by Region .................................................................................. 20

Figure 2.13: World Consumption of Ethylene by Region ............................................................................ 20

Figure 2.14: Top 15 Methanol Importers Between 2015-2019 .................................................................. 21

Figure 2.15: Top 15 Ammonia Importers Between 2015-2019 .................................................................. 23

Figure 2.16: Top 15 Ethylene Importers Between 2015-2019 .................................................................... 24

Figure 2.17: Top 15 Propylene Importers Between 2015-2019.................................................................. 26

Figure 2.18: World Imports Value of Petrochemicals ................................................................................. 27

Figure 2.19: Methanol Imports/Exports in Canada .................................................................................... 27

Figure 2.20: Ammonia Imports/Exports in Canada ..................................................................................... 28

Figure 2.21: Ethylene Imports/Exports in Canada ...................................................................................... 29

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vi Canadian Energy Research Institute

Figure 2.22: Propylene Imports/Exports in Canada .................................................................................... 30

Figure 3.1: Integrated Project economic model (IPEM) workflow ............................................................. 31

Figure 4.1: RBC Constant and Inflated Dollar Supply Cost of all Products in the Provinces ....................... 36

Figure 4.2: CBC Constant and Inflated Dollar Supply Cost of all Products in the Provinces ....................... 37

Figure 4.3: Comparison of Constant-Dollar Supply Costs for RBC and CBC Project Investments ............... 38

Figure 4.4: Comparison of Cash Costs for RBC and CBC Project Investments ............................................ 38

Figure 4.5: Cumulative Cashflow and Payback Period of Investment for the RBC Projects (US$) ............. 39

Figure 4.6: Cumulative Cashflow and Payback Period of Investment for the CBC Projects (US$) ............. 40

Figure 4.7: Cumulative Cashflows of CBC Projects Based on Inflated-dollar Supply Cost .......................... 41

Figure 4.8: Direct and Indirect Impacts on Canadian GDP by RBC Projects ............................................... 42

Figure 4.9: Direct and Indirect Impacts on Canadian GDP by CBC Projects................................................ 43

Figure 4.10: Direct and Indirect Impacts on Canadian (Provincial & Federal) Tax Revenue ...................... 44

Figure 4.11: Direct and Indirect Permanent Jobs Supported by New Projects .......................................... 45

Figure 4.1: Comparison of Regional Prices of

Methanol to the Estimated RBC and CBC Breakeven Prices ..................................................... 46


Ammonia to the Estimated RBC and CBC Breakeven Prices ..................................................... 47


Ethylene to the Estimated RBC and CBC Breakeven Prices ...................................................... 48


Propylene to the Estimated RBC and CBC Breakeven Prices .................................................... 48

Figure 4.5: Effect of Canadian Federal Carbon Tax Schedule on the Breakeven Prices ............................. 50

Figure D.1: Energy Consumption versus Production for the Chemical Sector in 2010 .............................. 70

Figure G.1: Methanol Production Process from Natural Gas ..................................................................... 85

Figure G.2: Ammonia Production Process from Natural Gas ...................................................................... 87

Figure G.3: Ethylene and Propylene Production Process from Naphtha .................................................... 89

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Economic Impacts of Value-Added Oil and Gas Products vii

List of Tables Table E.1: Economic Impacts of Product Supply in Business as Usual Scenario xv

Table E.2: Economic Impacts of Product Supply in Medium Supply Growth Scenario xvi

Table E.3: Economic Impacts of Product Supply in High Supply Growth Scenario xvii

Table 1.1: Breakdown of feedstock, Product, and Modelling Requirements 6

Table 3.1: Facility-level Investment Business Cases 32

Table 4.1: Average Pay Rate per Employment for Direct and Indirect Jobs Supported 45

Table 4.2: Economic Impacts of Product Supply in Business as Usual Scenario 51

Table 4.3: Economic Impacts of Product Supply in Medium supply Growth Scenario 52

Table 4.4: Economic Impacts of Product Supply in High Supply Growth Scenario 53

Table 5.1: Summary of Economic Impacts of Optimal Investments Under the Three Supply Scenarios 57

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Economic Impacts of Value-Added Oil and Gas Products ix

Acronyms and Abbreviations AB Alberta

BAU Business as usual

BC British Columbia

CBC Competitive Business Case

CEAA Canadian Environmental Assessment Agency

CERI Canadian Energy Research Institute

CER Canadian Energy Regulator

CIAC Chemistry Industry Association of Canada

CO2 Carbon Dioxide

CO2e Carbon Dioxide Equivalent (including all greenhouse gases)

ECCC Environment and Climate Change Canada

EIA Environmental Impact Assessment (Canada)

EIS Environmental Impact Statement (US)

EPA Environmental Protection Agency (US)

FERC Federal Energy Regulatory Commission (US)

FFE Feed plus fuel energy

FOB Free On Board

GDP Gross Domestic Product

GHG Greenhouse Gas

GHGRP Greenhouse Gas Reporting Program

GWP Global Warming Potential

HSG High Supply Growth

IEA International Energy Agency

IPEM Integrated Project Economic Model

IPCC Intergovernmental Panel on Climate Change

IRR Internal Rate of Return

kt Kilotonnes

kt/yr Kilotonnes per year

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LNG Liquified Natural Gas

LDPE Low Density Polyethylene

LPG Liquefied petroleum gas

LSR Light straight-run

Mbpd Million barrels per day

MBTU Million British Thermal Units

m3 Cubic meters

Mt Million tonnes

MSG Medium Supply Growth

Mtpa Million tonnes per annum (Million tonnes per year)

NGLs Natural gas liquids

ND North Dakota

NEB National Energy Board

NL Newfoundland and Labrador

NRCan Natural Resources Canada

ON Ontario

PHD Propane dehydrogenation

PGP Polymer grade propylene

RBC Reference Business Case

ROI Return on Investment

SMR Steam methane reforming

SK

tpd

Saskatchewan

Tonnes per day

tpy Tonnes per year

US The United States

July 2020

Economic Impacts of Value-Added Oil and Gas Products xi

Executive Summary Value-added activities for oil and natural gas, including petrochemical activities, are limited in Canada

compared to other jurisdictions. The Canadian Energy Research Institute (CERI) has assessed various

natural gas-based pathways to petrochemicals in previous studies, this report completes the cycle by

investigating both gas- and oil-based pathways.

In this study, economic impacts of four basic petrochemical products are assessed including methanol,

ammonia, ethylene and propylene, for new projects that could be sited in Canadian provinces with

significant oil and gas production. CERI identified the provinces of Alberta, Saskatchewan and

Newfoundland and Labrador as potential locations in Canada to meet this primary feedstock resources

availability criteria.

Detailed data on petrochemical process technologies and investment economics were used to develop an

Integrated Project Economics Model (IPEM) which combines process, microeconomic and

macroeconomic models to perform economic impact assessments on either brownfield or greenfield

petrochemical plants. Among other things, IPEM is used to estimate feedstock requirements, productivity,

supply cost for greenfield plants, cash costs for brownfield plants, investment payback period, gross

domestic product (GDP) impacts of capital and operating investments, tax revenue impacts, employment

impacts and salaries/wages impacts.

Two project investment business cases were used to categorize the entire results into a best-performing

and worst-performing investment economic and plant design decisions for new and existing facilities. The

best-performing case is referred to as the Competitive Business Case (CBC) and the worst-performing case

as the Reference Business Case (RBC). These two cases define the lower bound and upper bound on the

outcomes of the assessments performed in IPEM, and this allows us to bracket our findings accordingly.

Furthermore, results for the CBC type of petrochemical plant were applied to three product supply

scenarios covering a Business As Usual (BAU), Medium Growth Scenario (MGS), and High Growth Scenario

(HGS). A detailed description of each scenario is available in Chapter 3 on study methodology.

Price Competitiveness of Products

Figures E.1 to E.4 present CERI’s estimate of lower and upper limits of respective free on board (FOB)

origin breakeven prices for brownfield and greenfield RBC and CBC projects. The projects are optimally

located in Canada at the province where FOB prices of the product are lowest compared to the other

provinces. CERI’s estimate of the prices are compared to the range of 2019 prices reported for the

products in North America, Europe, and Asia.

Canadian methanol price for a RBC project is expected to be competitive in the three regions with FOB

origin price range of $219 to $366 per tonne, provided the landed cost is less than $442 per tonne in North

American regional markets, $410 per tonne in European markets, and $370 per tonne in Asian markets.

A greenfield CBC project will not only be competitive in all three regional markets but could also compete

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xii Canadian Energy Research Institute

with cash cost-priced suppliers in those markets, provided the landed cost is not more than $227 per

tonne. Estimated CBC plant’s FOB origin price range is between $147 to $244 per tonne.

Figure E.1: Comparison of 2019 Regional Prices of Methanol to the Estimated RBC and CBC Breakeven Prices

Canadian ammonia plant of the RBC type can be expected to be competitive in North American and Asian

regions on cash cost basis, but not in Europe. However, the landed cost in North American markets needs

to be no more than $350 per tonne and not more than $340 per tonne in Asian markets. A greenfield RBC

type plant in Canada cannot compete for market share in any of these regions. For Canadian CBC ammonia

plant, the product is expected to be competitive on both supply cost and cash cost basis provided the

landed cost in a North American market is not more than $350 per tonne, also not more than $275 per

tonne in European markets, and not more than $340 per tonne in Asian markets. FOB origin price range

for a CBC ammonia plant in Canada is estimated to be between $214 to $394 per tonne.

An RBC type naphtha cracking plant for ethylene production in Canada is unlikely to be competitive on

both cash cost and supply cost basis in any of the three regions of comparison. Estimated FOB origin price

range for such a plant is $1239 to $1563 per tonne. However, a CBC type naphtha cracker in Canada

producing ethylene is not expected to be competitive in North American markets but may be able to

compete in Europe and Asia if the landed costs in those markets is not more than $1220 per tonne and

$1176 per tonne, respectively. FOB origin price range for the CBC project is between $1037 to $1273 per

tonne.

0

50

100

150

200

250

300

350

400

450

500

North America Europe Asia RBC CBC

Pri

ce R

ange

(U

S$/t

)

Methanol Price

July 2020

Economic Impacts of Value-Added Oil and Gas Products xiii

Figure E.2: Comparison of 2019 Regional Prices of Ammonia to the Estimated RBC and CBC Breakeven Prices

Figure E.3: Comparison of 2019 Regional Prices of Ethylene to the Estimated RBC and CBC Breakeven Prices

0

100

200

300

400

500

600

700


Pri

ce R

ange

(U

S$/t

)

Ammonia Price

0

200

400

600

800

1000

1200

1400

1600

1800


Pri

ce R

ange

(U

S$/t

)

Ethylene Price

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xiv Canadian Energy Research Institute

Figure E.4: Comparison of Regional Prices of Propylene to the Estimated RBC and CBC Breakeven Prices

RBC type propylene production in Canada will not be competitive in Europe and Asia in supply cost nor

cash cost terms. However, it is likely to be competitive with the marginal propylene suppliers in North

American markets if the product from Canada is sold at slightly above cash cost basis with a landed cost

at the destination market not exceeding $1345 per tonne. FOB origin price for the RBC plant naphtha

cracking propylene ranges between $1239 to $1563 per tonne. A CBC type propylene cracker plant in

Canada is expected to be competitive in North America on both supply cost and cash cost, not competitive

in Asian markets at all, but only competitive in European markets on slightly above cash cost basis if the

FOB destination price does not exceed $1115 per tonne. FOB origin price range for the CBC propylene

plant is between $1037 to $1273 per tonne. However, in North American markets, FOB destination price

needs to stay below $1345 per tonne for competitiveness.

Product Supply Scenarios

The BAU scenario maintains current market conditions in Canada where there is domestic demand and

export demand, but the domestic demand is met by domestic production in addition to imports. Table E.1

shows the economic impacts of the BAU scenario where methanol production capacity is expected to

grow by 1.76 million tonnes per annum (MTPA) by the end of forecast period, reaching 2.34 MTPA by

2050 with total feedstock demand of 0.26 billion cubic feet (bcf) per day of natural gas. This will contribute

to economic impacts amounting to an annual GDP increase of $107.02 million by 2050, tax revenue

increase of $28.27 million, additional 103 direct permanent jobs, and increase in compensation of $1.21

million.

0

200

400

600

800

1000

1200

1400

1600

1800


Pri

ce R

ange

(U

S$/t

)

Propylene Price

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Economic Impacts of Value-Added Oil and Gas Products xv

Under the same scenario, ammonia production capacity is expected to grow by 1.85 MTPA by the end of

forecast period, reaching 7.19 MTPA by 2050 with total feedstock demand of about 0.58 bcf per day of

natural gas. This will contribute to economic impacts amounting to an annual GDP increase of $574.02

million by 2050, tax revenue increase of $48.96 million, 551 direct permanent job growth, and increase in

pay rate of $5.81 million.

Table E.1: Economic Impacts of Product Supply in Business as Usual Scenario

Economic Impacts

BAU

Total GDP

Increase

(USD Million)

Total Tax

Increase

(USD Million)

Direct

Jobs

created

Total Pay

Increase

(USD Million)

Methanol 2020 - - - -

2030 5.69 0.88 16 0.46

2040 44.30 9.30 64 0.75

2050 107.02 28.27 103 1.21

Ammonia 2020 - - - -

2030 68.99 4.70 199 2.04

2040 261.22 20.49 376 3.83

2050 574.02 48.96 551 5.81

Ethylene 2020 - - - -

2030 134.10 53.41 386 4.27

2040 604.83 280.04 870 10.21

2050 1,528.16 777.57 1,466 18.35

Propylene 2020 - - - -

2030 15.77 5.38 45 0.61

2040 79.67 33.09 115 1.37

2050 204.22 96.83 196 2.50

BAU ethylene production capacity is expected to grow by 7.78 MTPA by the end of forecast period,

reaching 12.71 MTPA by 2050 with total feedstock demand in crude oil equivalent of about 7.89 million

barrels per day (Mbpd) of WCS quality like crude or 3.76 Mbpd of SCO. This will contribute to economic

impacts amounting to an annual GDP increase of $1.53 billion by 2050, tax revenue increase of $0.78

billion, 1466 direct job growth, and increase in pay rate of $18.35 million. Propylene production is as

coproduct from the naphtha cracker but will result in additional economic impacts of annual GDP increase

of $204.22 million by 2050, tax revenue increase of $96.83 million, 196 direct job growth, and increase in

pay rate of $2.50 million.

Table E.2 shows the economic impacts of the MSG where methanol production capacity is expected to

grow by 3.64 MTPA by the end of forecast period, reaching 4.82 MTPA by 2050 with total feedstock

demand of about 0.53 bcf per day of natural gas. This will contribute to economic impacts amounting to

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an annual GDP increase of $262.99 million by 2050, tax revenue increase of $82.57 million, 252 direct job

growth, and increase in pay rate of $2.52 million. Under the same scenario, ammonia production capacity

is expected to grow by 1.94 MTPA by the end of forecast period, reaching 7.46 MTPA by 2050 with total

feedstock demand of about 0.60 bcf per day of natural gas. This will contribute to economic impacts

amounting to an annual GDP increase of $0.72 billion by 2050, tax revenue increase of $61.18 million, 689

direct job growth, and increase in pay rate of $6.59 million.

Table E.2: Economic Impacts of Product Supply in Medium Supply Growth Scenario

Economic Impacts

MSG

Total GDP

Increase

(USD Million)

Total Tax

Increase

(USD Million)

Direct

Jobs

created

Total Pay

Increase

(USD Million)

Methanol 2020 4.01 0.62 115 0.63

2030 50.34 10.90 145 0.97

2040 131.79 35.50 190 1.57

2050 262.99 82.57 252 2.52

Ammonia 2020 7.45 0.37 214 1.17

2030 122.33 8.31 352 2.69

2040 357.91 28.05 515 4.54

2050 718.59 61.18 689 6.59

Ethylene 2020 26.63 8.31 766 4.17

2030 426.14 171.52 1,226 9.40

2040 1,288.35 593.25 1,854 17.25

2050 2,748.08 1,384.92 2,636 28.00

Propylene 2020 15.08 4.76 434 2.36

2030 194.07 76.83 559 3.80

2040 513.16 231.80 738 6.13

2050 1,019.11 504.83 978 9.62

MSG ethylene production capacity is expected to grow by 10.27 MTPA by the end of forecast period,

reaching 16.79 MTPA by 2050 with total feedstock demand in crude oil equivalent of about 10.42 MMbbl

per day of WCS or 4.96 MMbbl per day of SCO. This will contribute to economic impacts amounting to an

annual GDP increase of $2.75 billion by 2050, tax revenue increase of $1.38 billion, 2636 direct job growth,

and increase in pay rate of $28.00 million. Propylene production is as co-product from the naphtha cracker

but will result in additional economic impacts of annual GDP increase of $1.02 billion by 2050, tax revenue

increase of $504.83 million, 978 direct job growth, and increase in pay rate of $9.62 million.

Table E.3 shows the economic impacts of the HSG where methanol production capacity is expected to

grow by 5.72 MTPA by the end of forecast period, reaching 7.57 MTPA by 2050 with total feedstock


July 2020

Economic Impacts of Value-Added Oil and Gas Products xvii

an annual GDP increase of $415.99 million by 2050, tax revenue increase of $140.99 million, 399 direct

job growth, and increase in pay rate of $3.98 million. Under the same scenario, ammonia production

capacity is expected to grow by 2.07 MTPA by the end of forecast period, reaching 8.00 MTPA by 2050

with total feedstock demand of about 0.65 bcf per day of natural gas. This will contribute to economic

impacts amounting to an annual GDP increase of $0.98 billion by 2050, tax revenue increase of $84.34

million, 938 direct job growth, and increase in pay rate of $8.15 million.

Table E.3: Economic Impacts of Product Supply in High Supply Growth Scenario

Economic Impacts

HSG

Total GDP

Increase

(USD Million)

Total Tax

Increase

(USD Million)

Direct

Jobs

created

Total Pay

Increase

(USD Million)

Methanol 2020 6.39 1.23 184 1.00

2030 80.03 20.29 230 1.54

2040 208.95 62.80 301 2.48

2050 415.99 140.99 399 3.98

Ammonia 2020 14.91 0.85 429 2.34

2030 200.35 14.35 577 3.97

2040 522.11 41.95 751 5.96

2050 977.99 84.34 938 8.15

Ethylene 2020 48.62 15.66 1,399 7.62

2030 680.57 275.87 1,959 13.98

2040 1,891.42 871.36 2,722 23.52

2050 3,828.88 1,924.97 3,673 36.59

Propylene 2020 26.90 8.71 774 4.22

2030 336.63 135.50 969 6.46

2040 868.79 396.73 1,250 10.10

2050 1,693.17 844.49 1,624 15.56

HSG ethylene production capacity is expected to grow by 12.48 MTPA by the end of forecast period,

reaching 20.41 MTPA by 2050 with total feedstock demand in crude oil equivalent of about 12.68 Mbpd

of WCS or 6.04 Mbpd of SCO. This will contribute to economic impacts amounting to an annual GDP

increase of $3.83 billion by 2050, tax revenue increase of $1.92 billion, 3673 direct job growth, and

increase in pay rate of $36.59 million. Propylene production is as coproduct from the naphtha cracker but

will result in additional economic impacts of annual GDP increase of $1.69 billion by 2050, tax revenue

increase of $0.84 billion, 1624 direct job growth, and increase in pay rate of $15.56 million.

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xviii Canadian Energy Research Institute

Apart from these direct impacts,there are indirect and induced impacts driven by such investments within

the broader economic sectors interacting in some way with the petrochemical sector at both provincial

and national levels.

In conclusion, the gas-based petrochemicals value chain seem to be more suitable and economic for

Canada than the oil-based (naphtha) pathway. To produce enough naphtha locally for the projected

petrochemical products supply scenarios would require multiples of additional refining capacity in

Canada, which is quite unlikely on the radar due to economics and other reasons around the market for

the other refinery co-products. However, these projects can contribute in many ways to Canadian

economy which can be evaluated through their contributions to provincial and national GDPs, tax revenue

generation, job creation, and employee salaries/wages. Consequently, petrochemical investments in

Canada might need to focus on gas-based pathways. Already, a number of ongoing project developments

have done so.

July 2020

Economic Impacts of Value-Added Oil and Gas Products 1

Chapter 1: Introduction

Background

The Canadian Oil and Gas industry has seen a gradual increase in investments and production volumes for

decades. Since a profound oil price decrease in 2014, the Canadian oil and gas sector has been fraught

with multiple challenges such as lower prices, minimal new investments, and persistent market access

limitations resulting in a single-exporter market for Canadian production. More recently, the industry has

faced even greater challenges, such as world market oversupply – including storage limitations – resulting

in extremely low oil and gas prices. Moreover, recent COVID-19 pandemic has resulted in substantial

reductions in demand for oil and gas.

Canada ranks in the top ten for both global oil and gas production, and the oil and gas industry is one of

the main contributors to Canadian gross domestic product (GDP). The ongoing issues identified supra,

along with the usual cyclical nature of commodity prices mean that the contribution to the overall

economy is volatile. This is particularly so for those provincial economies with high oil and gas

dependency, such as Alberta, Saskatchewan, and Newfoundland and Labrador.

Industry experts and analysts have highlighted the benefits of expanding the petrochemical sector to

attract new investments into Canada and strengthen the economy. Such investment diversity would also

support the oil and gas industry, which produces the feedstocks for this sector, and exposes the investor

to a wider spread between feedstock and product prices.

Canada already boasts one of the best chemical and petrochemical industries in the world with world-

class and state of the art technologies to minimize the carbon footprint from their production activities.

Nevertheless, while a number of petrochemical investments have taken place in Canada in recent years,

there is a widely held view that Canada has not explored its full capacity in the petrochemical sector (CIAC

2019).

CERI has studied the Canadian petrochemical industry for many years and has produced detailed

modelling and results for many petrochemical value chains, especially via gas-based feedstocks such as

methane (natural gas) and natural gas liquids (NGLs). This report aims to complete the study cycle by

examining an oil-based feedstock (naphtha), and other natural gas-based value-added products.

This study investigates the project economics of ethylene and propylene production from naphtha, and

methanol and ammonia production from natural gas feedstock. The idea of value-added in this context is

from a perspective of the economy-wide additional macroeconomic impacts of potential investments in

those value chains.

There are also other benefits associated with diminishing the impact of cyclical commodity pricing and

from limiting the impacts of market access constraints on Canadian oil and gas industry growth. The study

also discusses future research areas considering carbon fibre and asphalt production from bitumen as

value-add products.

July 2020

2 Canadian Energy Research Institute

Ongoing Investment Challenges and Access to Market Issues

Canada’s crude oil production has increased in recent years, resulting in more income, profits, and

royalties to the Canadian economy. According to Natural Resources Canada (NRCan), Canadian crude oil

production grew from 1.9 million barrels per day in 2000 to more than 4.4 million barrels per day by 2019,

of which about 64 percent now comes from the oil sands. Under normal market conditions, Canada

exports about 3.7 million barrels per day, of which 96 percent are sent to the US market. Interestingly,

many US refineries are configured to process heavy crude oil slates like that produced from the oil sands

in Canada.

Canadian producers have been keen to gain access to Asian markets, which would provide them with

greater optionality with the prospect of better prices for their product and increased revenues. There has

also been a growing demand for energy products in Asia due to increasing industrialization and population

growth. Asian economies are expected to continue growing, thus providing Canada with potential

markets to diversify and export oil and gas directly as well as other end-use products such as LNG and

petrochemicals.

Due to limited pipeline capacity, market access constraints have been a major barrier to the oil and gas

industry. A number of pipeline expansion capacity projects in Canada have been proposed to allow greater

shipments from the land-locked oil and gas producing provinces such as Alberta or Saskatchewan,

including some proposed pipelines through British Columbia, which would provide access to Asian

markets. While many experts have acknowledged the potential economic benefits of building new

pipelines or expanding existing ones, such major projects have faced delays and cancellations due to

environmental, social or Indigenous concerns (Mirkovic 2016).

While the oil and gas industry is impacted by many local factors such as storage limitations, market access

and government policies; global supply and demand dynamics remains the primary factor driving prices,

and hence, investments. Since the oil price crash in year 2014, capital investment has been reduced

significantly (CERI 2019b). Government policies are usually used to support the industry during difficult

times through tax incentives/credits, royalty credits, loan guarantees, etc., (CERI 2020). This enables the

industry to continue to employ more skilled workers in high paying jobs, which provides substantial

economic benefits for Canadians generally and ultimately for government revenues as a result of higher

levels of economic activity.

Role of Diversification and Growth of Petrochemicals Production

Oil and gas is a challenging business, particularly in Canada today due to global competition for investment

and the market access challenges Canadian producers are facing. Petrochemical diversification has been

recognized and encouraged by many governments as a path to greater economic opportunities (Doyle

2019; CIAC 2019). Alberta’s Petrochemicals Diversification Program was designed to encourage

investments in the petrochemical sector by providing royalty credits to investors. Saskatchewan’s

Manufacturing and Processing incentive, and the Oil and Gas Processing Investment incentive programs

provide tax credits to various types of investments, including petrochemical sector investments

July 2020


(Government of Alberta 2019, Government of Saskatchewan 2020). These are good examples of

government interventions to drive petrochemical diversification.

Methanol, ammonia, ethylene, and propylene are basic petrochemical building blocks to various

derivatives and end-use value chain products. Methanol and ammonia are generally produced from

natural gas feedstock which creates growth opportunities in the upstream natural gas production

operations. In many countries, changes in environmental policies have focused attention to methanol as

an alternative for the gasoline used in internal combustion engine vehicles and as bunker fuel for marine

transportation. Methanol contains a low amount of carbon compared with gasoline and has zero sulphur

content, producing minimal contaminants during combustion, thereby making it environmentally friendly.

Ammonia is a commodity that has the potential to see its demand increase continuously along with the

increase in world population due to its use in fertilizers in the agricultural sector. Ammonia is also seen as

a hydrogen-carrier that could remove logistical challenges to hydrogen transportation if it can be easily

recovered at a point of use. Currently, Canadian ammonia production stands at about 5,000 Mt per year.

Urea, which uses ammonia as a main feedstock, has an annual output of over 4,000 Mt per year. The

demand for ethylene and propylene are known to be correlated to GDP growth, which indicates the

potential increase in demand for these products as economies continue to grow over time (ICIS 2017).

They serve as the building blocks for numerous end-use petrochemical and plastic materials.

Figure 1.1: Distribution of Oil Demand in the OECD in 2017 by Sector

July 2020


As seen in Figure 1.1, petrochemicals are the second major source of crude oil demand and have

witnessed continuous growth for many years. Investing in the petrochemical sector in areas with cheap

and abundant feedstocks has been observed to have economic merit, both locally and nationally. In

Canada, provinces such as Alberta, Saskatchewan, British Columbia, and Newfoundland and Labrador

could be viewed as potential locations given the availability of oil and gas in those areas. British Columbia

has, unlike Alberta and Saskatchewan, has direct access to tidewater. However, the province produces

very little oil relative to its gas production. Newfoundland and Labrador mainly produces offshore oil and

associated gas but the province has direct access to tidewater and a new petrochemical plant in the

province can be sited in proximity to major petrochemical hubs in Ontario and Quebec. There is also a lot

of refinery capacity in eastern Canada where oil-based petrochemical feedstocks such as naphtha might

be readily available to plants in this region. Coastal provinces could also import naphtha from US refineries

or from other global sources. The economic growth due to investments in petrochemicals and the

petrochemical industry’s potential to provide stable benefits for extended periods are positive drivers for

diversification away from raw natural resource economy. Canada should benefit if investments are

competitive relative to other supply jurisdictions.

Why Canada Should Invest In Value-added Products

Crude oil and natural gas markets are heavily influenced by global demand supply dynamics. The effect

can be amplified in capacity-constrained regional markets such as Canada; with market access issues,

discounted crude/gas prices and lack of storage capacity. As seen recently, low market prices could have

a negative impact on the Canadian economy. On the other hand, value-added petrochemicals is an

industry that extends the oil and gas value chain resulting in additional revenue and profit for integrated

companies, and further macroeconomic benefits to the host regional, provincial and national economies.

Hence, extending crude oil and gas value chains in the resource-rich provinces like Alberta or

Saskatchewan will minimize the impacts of natural resource price volatility and create more opportunities

for the Canadian energy sector. This could be viewed as a way forward for the industry and government

in terms of profitability and revenue generation.

Canadian capacity to produce petrochemicals is not close to being maximized yet given the large resource

base available in this country. Petrochemical investments would bring more jobs, GDP, tax revenue, and

other public benefits to the economy (CERI 2018). In addition, the Canadian chemical and petrochemical

industry has seen a 67 percent reduction in greenhouse gas (GHG) intensity since 1992, because of

operational improvements and significant investment in best practice technologies. Globally, the chemical

and petrochemical sector is a $5 trillion industry with annual growth rates nearly double global GDP

growth in each of the past 10 years. The Chemistry Industry Association of Canada (CIAC) forecasts expect

a tripling in demand for chemicals over the next 20 years (CIAC, 2019).

Currently, Alberta and Ontario are Canadian provinces with the largest petrochemical installed capacities.

Alberta uses predominantly ethane and ethylene as feedstocks for basic chemicals and derivatives, with

an installed capacity of 2745 kt/yr, distributed amongst 17 facilities. In Alberta, the petrochemical

products produced range widely from Low Density Polyethylene (LDPE) to Polymer Grade Propylene

(PGP). In Ontario’s case, ethane (30 percent), propane (32 percent), butane (28 percent), in addition to

July 2020


naphtha (10 percent) are the most commonly used feedstocks. The capacity installed is 1550 kt/yr, which

is distributed among eight plants in the province.

Since the 1990s, the Chinese economy has grown steadily, attracting more investment capital, driving up

energy demand, and the petrochemicals required by the manufacturing industry or used to blend

transportation fuels. Many countries in Asia have experienced similar economic growth as China recently,

drawing investments and increasing demands for energy and petrochemicals. As seen in Figure 1.2, Asia

has the largest chemical sales market, almost three times more than second- place Europe. Since 2000,

the Asian region has been the leader in economic growth in the world, suggesting that Canada would

benefit greatly from better market access for serving these markets.

Figure 1.2: Value of Chemical Sales Worldwide in 2018

As a major oil and gas producer, Canada is well-positioned to take advantage of further diversification to

value-added petrochemicals production. Investing in major high growth and widely applicable base

petrochemicals such as ethylene, propylene, ammonia, and methanol – with a focus on reaching markets

both domestically and internationally – could be a solution to reduce exposure to world oil and gas price

fluctuations as well as limitations on serving markets outside North America.

July 2020


Focus of the Study

North America, including Canada, has an abundant unconventional gas resource from which natural gas

liquids are extracted for various industrial uses. Consequently, NGLs have become the dominant feedstock

for the petrochemical industry in Canada and the US. However, value-added activities for oil and natural

gas, including petrochemical activities, are limited in Canada compared to other jurisdictions.

The objective of this study is to investigate the economic impacts and viability of investments in four basic

petrochemicals including: ammonia; methanol; ethylene; and propylene, in the three Canadian provinces

of Alberta, Saskatchewan, and Newfoundland and Labrador where oil and gas production are major

contributors to the provincial economies. British Columbia has been excluded in the assessment because

it mostly produces gas and has access to tidewater. Table 1.1 shows a breakdown of feedstocks, products,

and assessment methods to be implemented in this study.

Table 1.1: Breakdown of feedstock, Product, and Modelling Requirements

Feedstock Product Assessment Methods

- Gas-based (natural gas feedstock)

- Oil-based (naphtha feedstock)

- Ammonia, Methanol

- Ethylene, Propylene

- Process (amounts of feedstocks, products and GHG emissions)

- Microeconomic (FOB supply cost)

- Macroeconomic (employment, salary/wage, tax revenue, GDP impacts)

We are restricting the focus to products at the intermediate level within the value chain, from where

various final products can be produced further down the value chain. This enables us to understand the

effect of pressures on various finished products’ demands on the supply of intermediate products, basic

products, and feedstocks.

Economic impacts are assessed from the provincial and national macroeconomic impacts on GDP, tax

revenues, job creation and wages/salaries. Economic viability is evaluated for various configurations of

the petrochemical plant design in the form of plant gate or free on board (FOB) origin supply cost (which

excludes cost of shipment to destination market) of the product.

Using detailed industry data on petrochemical project economics and facility attributes, this study

categorizes the overall analysis into two broad business cases referred to as the Reference Business Case

(RBC) and the Competitive Business Case (CBC). RBC represents the projects with investment and facility

design attributes, which may limit overall economic impacts. In contrast, CBC represents the upper bound

on the investment decisions to optimize overall economic impacts. These two cases are expected to

prescribe the lower and upper limits of the economic impacts of new projects developed in the likes of

those captured in the industry data used in this study.

July 2020


The study also develops three product supply scenarios based on CERI’s demand projections for the

products evaluated - as detailed in the methodology section. The scenarios include business as usual,

medium growth, and high growth scenarios. For each scenario, the overall economic impacts over a 30-

year period (2020-2050) are evaluated in addition to the primary oil and gas feedstock requirements.

The following sections of this report will review the petrochemicals market, feedstock demand and supply

and technologies for producing the products. Chapter 3 presents the methodology, while results are

discussed in Chapter 4 and conclusions drawn in Chapter 5.

July 2020


July 2020


Chapter 2: Overview of the Petrochemical Market Outlook

Oil and Gas Petrochemical Feedstocks

Petrochemicals can be produced from various types of feedstocks. Figure 2.1 highlights a forecast of

petrochemical feedstock consumption globally. As shown in the Figure 2.1, petrochemical production

from oil and gas is expected to continue to increase, and as a result, demand on feedstocks will increase

as well. Crude oil remains the primary petrochemical feedstock overall, despite recent trends with some

petrochemical production pathways shifting to natural gas as the primary feedstock, especially where gas

is cheap and abundant. One example is some of the ethylene and propylene production plants being

reengineered to use ethane-propane (NGL) instead of light naphtha. Ethane and propane continue to be

cheap feedstocks in North America, due to depressed natural gas prices and the regional nature of the

gas market.

Figure 2.1. World Petrochemical Feedstock Consumption

Source: (IEA 2018), Graph by: CERI

In past CERI studies, we have looked closely at natural gas and natural gas liquids (NGL) feedstocks. CERI

Study 181 (CERI 2019c) highlighted the use of several feedstocks to produce ethylene and propylene. The

studied feedstocks include ethane, propane, liquefied petroleum gas (LPG), and light naphtha. In the

following sections, we take a closer look at the potential feedstocks for the four products studied in this

study.

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Feedstocks for Methanol Production

Methanol is typically produced on an industrial scale using natural gas as the main feedstock. However,

methanol can be made from other types of feedstocks, including coal, biomass, municipal solid waste,

biogas, waste CO2, and even from the products of electrolysis using renewable electricity. A typical

methanol plant will produce around 5,000 metric tons of methanol per day by steam reforming natural

gas and converting synthesis gas produced to liquid methanol.

According to industry experts, around 90 percent of methanol comes from using natural gas, and 9

percent from using solid fuels such as coal, biomass, municipal solid waste and other solid derived

biogases (.

Figure 2.2). The rest includes CO2 and chemical derived methanol production (Dalena et al. 2018; Keim

2014; NETL 2014).

Figure 2.2: Global Methanol Feedstock Breakdown

Source: (Dalena et al. 2018; Keim 2014; NETL 2014) Graph by: CERI

Feedstock for Ammonia Production

Natural gas and naphtha are the main feedstocks for ammonia production. Around 72 percent of

produced ammonia is from steam reforming of natural gas, as illustrated in Figure 2.3. Steam methane

reforming (SMR) method is currently the least energy-intensive technique. In China, coal is intensively

used, although the coal-based production process involves a higher energy requirement. About 75

percent of the ammonia produced in China is from coal, whereas in Canada it is mostly produced from

natural gas feedstocks.

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July 2020


Historical records indicate that ammonia plants in China have an estimated average energy intensity of

about 49.1 GJ/tonne of ammonia, resulting in specific emissions of about 2.3 tonne CO2 per tonne of the

product. In Canada, average energy intensity is about 33.8 GJ/tonne with specific CO2 emission of about

1.8 tonnes per tonne of the product (NRCan, 2008). Eleven ammonia plants are operating in Canada.

Ammonia production plants in Canada are ranked internationally as having the highest feed plus fuel

energy (FFE) efficiency, which consumes a typical of 33.8 GJ natural gas per tonne of produced ammonia.

In terms of other conventional resources, heavy fuel oil, coal, coke, oven gas and refinery gas can be used

as feedstock in ammonia production (Bicer et al. 2016).

Figure 2.3: Global Ammonia Feedstock Breakdown

Source: (Bicer et al. 2016) Graph By: CERI

Feedstock for Ethylene and Propylene Production

Ethylene and propylene, in general, are produced from the same feedstock in the same plant. The

potential feedstocks include ethane, propane, LPG, butane and naphtha. CERI Study 181 highlighted the

potential end product mix from different types of ethylene/propylene plants. A summary is illustrated in

Figure 2.4 (CERI 2019c).

Ethane and propane NGLs are extracted either from the gas stream in natural gas processing plants, off-

gas plants, crude bitumen upgraders, or as side-products from refineries. Ethane is mainly used to produce

ethylene while propane is used partly for heating purposes and as a petrochemical feedstock mix (with

ethane) to co-produce mainly ethylene and propylene. Naphtha is an intermediate hydrocarbon liquid by-

product containing paraffin, naphthenes, and aromatic hydrocarbons. Light naphtha (also called light

straight-run [LSR] naphtha) consists of molecules such as pentanes plus that have primarily five carbon

atoms (or slightly more) per molecule. It is derived from the crude oil distillation process in refineries or

NGLs separation in an NGL fractionation plant (McKinsey, n.d.). Steam cracking of light naphtha results in

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July 2020


the production of ethylene, propylene, and a C4 stream that includes butadiene, isobutylene, and n-

butenes (CERI 2019c).

Figure 2.4: Ethylene and Propylene Output for Different Feedstocks

Source: (CERI 2019c)

There is a clear distinction between the feedstock mix used in North America/Middle East and

Europe/China, as shown in Figure 2.5. North America and the Middle East are the lowest cost

petrochemical producers, with the feedstock made up of mainly NGL (ethane, propane, and butane),

whereas naphtha is the dominant feedstock in Europe and China. While North America and the Middle

East remain advantaged in terms of overall feedstock costs, the price gap narrows between North

America/Middle East and Europe/China during low oil price periods such as the one seen in late 2019 and

in 2020 (Deloitte 2019).

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July 2020


Figure 2.5: Regional Ethylene and Propylene Feedstock Breakdown

Source: (Deloitte 2019). Figure by CERI

Feedstocks Supply Demand Outlook

World Feedstock Outlook

World petrochemical feedstock demand is expected to increase in the upcoming years. However, oil and

gas demand does not solely depend on the petrochemical industry. The increasing energy demand,

increasing transportation demand, and other factors contribute to the demand and supply increase, as

predicted by CERI 2019 Study 181 (CERI 2019c). By the year 2030, petrochemicals are set to account for

more than a third of the growth in world oil demand and will continue to increase to half the growth to

2050. This is expected to add 7 Mbpd of oil by 2050. Similarly, the petrochemical industry will also

consume an additional 56 billion cubic metres (bcm) of natural gas annually by 2030, and 83 bcm by 2050

(IEA 2018). This highlights the growing interdependence and importance of integration between the

energy and petrochemical sectors. Global petrochemical feedstock and end products outlook are

illustrated in Figure 2.6, where HVCs are high-value chemicals such as light olefins (ethylene and

propylene) and other chemicals.

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July 2020


Figure 2.6: The World Petrochemical Feedstock and End Products Outlook

Source: (IEA 2018)

Naphtha Supply Demand Outlook

In 2016, naphtha accounted for 42.5 percent of the global feedstock supply for ethylene production.

However, this market-leading position is expected to decline to below 40 percent by 2021 as ethylene

production (especially in the North American petrochemical sector) becomes increasingly focused on cost-

advantaged NGL feedstocks such as ethane. The global estimated net increase in naphtha demand by

2035 is 1.8 Mbpd. Naphtha only makes up about 4 percent of the refined products from Canadian

refineries and is not a major feedstock for the western Canadian petrochemical sector, which relies

primarily on ethane feedstock. The eastern Canadian (Ontario) petrochemical sector, however, utilizes C2

to C5 feedstocks to produce ethylene, propylene and other co-products (e.g., butylene and butadiene). In

the US, naphtha and ethane dominate the petrochemical feedstocks. However, due to the lower-cost

ethane production from shale and tight gas activities, several expansion projects have been planned to

switch from naphtha to ethane feedstock for steam crackers. Naphtha is the predominant feedstock used

in the South Korean petrochemical sector to manufacture ethylene, propylene and other derivatives (CERI

2019c).

Naphtha is a refinery co-product, and hence the supply is largely impacted by the existing refinery

capacity. Currently, Canada has only 17 refineries countrywide processing slightly less than 2000 Mbpd of

various crude oil blends, of which about 65 percent of the capacity is in the eastern part of the country.

Hence, increasing refinery capacity in provinces such as Alberta and Saskatchewan becomes a significant

factor in making naphtha to ethylene and propylene technological pathway a reality. Figure 2.7 presents

a capacity breakdown of each of the province’s refinery capacity.

July 2020


Figure 2.7: Refinery Capacity of Canadian Provinces

Source: (Statistics Canada 2018), Graph By CERI

Naphtha prices have been in decline recently, according to industry experts. Two factors have contributed

to this; first, the oversupply of light crude oils where naphtha is not used as a blending product, and,

secondly, petrochemical sector shifting more towards natural gas and NGL feedstocks due to low natural

gas and NGL prices (Clay Boswell 2015; Prem and Wittels 2019). More recently, the impact from COVID-

19 pandemic has seen naphtha price drop by around 65 percent between January and April 2020. While

prices are expected to rebound in the upcoming months, current demand level remains low, with

continuous oversupply and storage issues preventing a gain in prices.

Overall, naphtha demand is expected to increase globally by between 1.5 percent to 2 percent annually,

with the lower range of the growth prevailing up to the year 2025, after which there would be an

additional 0.5 percent increase. This demand increase is mainly attributed to the expected production

increase of heavy crude oils. Some reduction of demand is expected in the years 2020 and 2021, due to

the COVID-19 pandemic.

Provided that Canadian refinery capacity could be increased, higher production of crude oil will

significantly impact the Canadian naphtha supply. Canadian crude oil production is expected to continue

to increase in the near future based on CERI’s 2019 forecast, as illustrated in Figure 2.8 (CERI 2019b). In

addition, it is expected that there would be a gradual increase in bitumen production according to CERI

Study 183. These conventional and heavy crude blends are processed by various refineries in Canada and

worldwide.

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Figure 2.8: Canada Crude Oil Production Forecast

Source: CERI

In general, North American naphtha prices are expected to decline. Naphtha prices reflect both

oversupply and crude oil prices.

Natural Gas Supply Demand Outlook

Canadian and US natural gas markets are largely integrated. A few key factors contribute to this: the

location of supply basins, demand centers, transportation infrastructure, and existing Canada – US trade

agreements. Traditionally consumers and distributors from both sides of the border have been able to

access natural gas from the cheapest supplier.

Natural gas has seen higher production in recent years, caused by two factors: addition to the US’s net

exports by 0.4 bcf/d and an increase in domestic gas consumption. However, the net exports to the US

started to decline in 2017 and are expected to continue to do so for the foreseeable future. Figure 2.9

shows CERI’s Canadian natural gas production forecast in 2019. Growth in Canadian domestic demand by

2.5 bcf/d in the next 20 years will mostly, but not completely, counterbalance this decline of net exports.

The incremental domestic demand is expected to come from the electricity sector, which explains 47

percent of growth, followed by industrial demand, which drives 35 percent of gas demand additions,

including the oil sands sector, as illustrated in Figure 2.9 (CERI 2019a).

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July 2020


Figure 2.9: Total Canadian Natural Gas Production

Source: CERI

Similar to the forecasts of Canadian production by other agencies, CERI’s forecast assumes that the

ongoing LNG industry developments in Canada will contribute to the increase in demand. According to

CER Energy Futures 2019, natural gas production and demand are expected to increase in the long term,

but having a slowed growth in the years 2023-2025 due to declining exports to the US (CER 2019).

In 2018, average natural gas exports to the US were 7.8 Bcf/d, and US imports were 2.2 Bcf/d in the same

year. The value of net natural gas in 2018 was $6.1 billion. The majority of natural gas is currently exported

to the US via pipelines and a smaller amount is trucked. LNG exports remain low; however, with the

expected new capital investments both LNG exports and natural gas production after 2025 are expected

to increase (CER 2020b).

Currently, the industrial sector accounts for around 54 percent of natural gas usage in Canada. The

industrial sector includes energy, heating and petrochemical feedstocks. Also, 1/3 of the NGLs are

currently used by the petrochemical industry. In the US, natural gas is expected to remain the most used

energy source. In addition, the forecast is that the US bulk chemical industry will increase the natural gas

feedstock usage by 51 percent (EIA 2018; 2020).

Natural gas prices in North America are expected to remain low in the foreseeable future with prices at

Henry Hub expected to be around USD$4/MMBtu, according to EIA (EIA 2020).

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Figure 2.10: Natural Gas Usage by Sector

Source: (EIA 2018; 2020), Graph by: CERI

Provincial Feedstock Overview

Alberta

Alberta has the most significant mid-stream natural gas and natural gas liquids production and resources,

accounting for 67 percent of total Canada natural gas production. Production increased by 7.2 percent

from 2014 to 2018, reaching 12.6 Bcf/d. There are cost advantages primarily in sourcing low-cost natural

gas as a feedstock, which is used in the Haber-Bosch process, the key commercial method of ammonia

production in Canada. According to CERI's previous studies, Alberta expects an increase from 839 new

wells drilled and tied-in 2019 to 1,236 wells drilled and tied-in during 2039 (CERI 2019a).

Saskatchewan

Compared to Alberta, Saskatchewan’s natural gas and NGL production is smaller. About 75 percent of the

gas production in the province comes from associated gas. Production of NGL is focused in Estevan, the

southeast of the province. Natural gas production in Saskatchewan is expected to decline over the next

20 years due to Canadian producers’ preference for other plays in British Columbia and Alberta.

Newfoundland and Labrador

Newfoundland and Labrador have an abundant offshore oil resource base. They produce oil from

Hibernia, Terra Nova, White Rose, North Amethyst, and Hebron, combined with imports from different

countries, mainly the US, and smaller imports also from Africa, Russia, and Europe. In 2017, 60 percent of

total imported crude oil from the US to Canada was received by the Newfoundland industries. However,

the Newfoundland government has announced an aggressive target to triple offshore crude production

to 650,000 bpd by the year 2030 (Senate Canada 2018).

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July 2020


Supply Demand and Market Outlooks for Petrochemicals

Supply and Demand Outlook

Methanol

Global methanol demand had significant growth over the past few years and is expected to increase based

on the following factors (MMSA 2020a):

A marginal increase in the market demand for methanol over the last 5 years (4-5 percent increase

per year) for more than 14 products consuming methanol.

A marginal annual increase in the demand for formaldehyde, which consumes around 25 percent

of the total methanol production.

Significant increase in demand for Methanol-to-Olefins (MTO), which increased 52 percent

between 2015-2019 (annual growth of around 10 percent), mainly due to the addition of new

olefins facilities (ethylene and propylene) in China.

Related methanol vehicle policies in China such as launching pilot projects over the last decade to

test methanol vehicle in target markets before the deployment on a national level.

Possible game changer for the methanol market in the near term are the potential for: methanol-

based fuels that blend with gasoline at proportions as high as 85 percent (i.e. M85) in China or

even the possibility for using neat methanol (100 percent methanol) as fuel, methanol as a marine

fuel to meet the IMO 2020 sulphur content requirements in marine bunker fuels which took effect

in January 2020, adoption of various clean fuel standards or low-carbon fuel regulations by many

countries, and upcoming petrochemicals projects to produce olefins through the MTO process.

July 2020


Figure 2.11: Capacities of Methanol Derivatives Between 2015-2019

Source: Methanol Institute 2020. Graph by: CERI

Figure 2.11 demonstrates the future potential of the methanol demand based on the last five years'

annual growth rate for each product. Again, the key products would be formaldehyde, MTO, methanol

blending with gasoline, and methanol as a fuel (MMSA 2020a).

Ammonia

A marginal increase is expected due to the current oversupply in the ammonia market. The total global

production is expected to increase by 4 percent over the next 5 years. The expected ammonia plants will

be mainly in Africa, Eastern Europe, and East Asia (DOI 2020).

Over the last five years, the US reduced ammonia imports by almost 50 percent. The number of ammonia

plants in the US increased mainly due to the availability of cheap natural gas. Currently, there are 35

ammonia plants in 16 states (DOI 2020). The increased capacities in the US reduced Canada’s market share

in the US market (Nutrien 2019).

In addition to the US production increase, Canada’s major challenge is that major importers such as India,

Morocco, South Korea, and China buy ammonia from the Middle East. Feedstock price, operating

expenditures and environmental regulations would affect the cost competitiveness to be able to access

these markets.

Currently, China is the world’s major ammonia supplier. However, in recent years there has been an

increase in North American ammonia production and a reduction in East Asian countries (Figure 2.12),

mainly driven by low natural gas prices in North America.

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Figure 2.12: World Ammonia Production by Region

Source: (IFASTAT 2019). Figure by CERI

Ethylene

The world consumption for ethylene is expected to increase by 6.5 million tonnes per year between

2020-2025. Figure 2.13 shows the world’s consumption, mainly driven by Asia and North America.

Figure 2.13: World Consumption of Ethylene by Region

Source: CERI 2019

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Propylene

The propylene demand market is expected to increase in the long term. However, some challenges can

impact the growth due to related regulations on the single-use of plastics. As more of these policies come

into force, it will reduce the polypropylene consumption, eventually reducing the propylene demand. It is

important to note that single-use plastics maintained 30 percent of the global polypropylene demand

during the 2020 COVID-19 pandemic to ensure the timely supply of hygienic products.

In the short term, the implication from COVID-19 has created a temporary market shock that will recede

as pre-COVID business conditions are restored.

Petrochemical Market Outlook

Methanol

Based on CERI’s analysis using the trading database of the International Trade Centre (ITC – a United

Nations and World Trade Organisation collaborative programme), the total value of the world’s methanol

imports reached $10.4 Billion in 2019. Figure 2.14 shows the dollar value for methanol imports over the

last five years for the top 15 methanol importers. The trends over five years of annual growth show a

steady increase in the methanol market. It is important to note that the main driver for this market is

China, which consumes 28 percent of the world's imports (ITC 2019).

Figure 2.14: Top 15 Methanol Importers Between 2015-2019

Source: Data from ITC,2019. Figure by CERI

The top five methanol exporters in 2019 are Trinidad and Tobago (15 percent), Saudi Arabia (12.2

percent), Iran (10.7 percent), US (8.7 percent), and Oman (8 percent). The market share by continent

comes mainly from Asia, where the Middle East and East Asian countries export around 47 percent of the

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global exports (OEC 2019). The North American exports are around 24 percent (including Trinidad and

Tobago), whereas Canada has around a 1 percent market share.

The annual growth in exports’ value between 2015-2019 has been moderate for the majority of exporters.

Canada has an 18 percent annual growth. Few countries such as Lithuania, UAE, Sweden, Egypt, and Serbia

have seen a significant increase in annual growth. However, the US had the best performance among

exporters, increasing its positive trade balance, decreasing their methanol imports and achieving a

significant annual growth of 52 percent in the value of methanol exports (ITC 2019).

Countries importing above 1 percent of the total world methanol are mainly distributed in the markets of

eight countries in Asia, another eight countries in Europe, and one country in South America (Brazil).

The shipping distance between importer and exporter is an important factor in international trade.

However, the data shows longer distances (source to destination) to the Asia Pacific markets compared

to the European and South American markets. For example, the average distances from supplier to

importer is 8,030 Km to China, 9,576 Km to Japan, 10,356 to South Korea, 4,969 Km to The Netherlands,

1,623 Km to Germany, and 3,431 Km to Brazil (ITC 2019).

The average tariff varies by country except for the European Union, which is fixed at 1.4 percent. The

highest tariffs for methanol imports are in Asia, where the average tariff is 6.5 percent in China, 4.7

percent in Indonesia, 4.2 percent in India, 1.2 percent in South Korea, 0.5 percent in Taipei and

insignificant in Japan, Thailand, and Singapore. It is important to note that the percentage of tariffs is one

of the factors that determine whether to import or produce domestically.

Ammonia

The total value of the world’s ammonia imports is $5.8 Billion in 2019 (ITC 2019). Figure 2.15 below shows

the dollar value of the ammonia imports over the last five years for the top 15 ammonia importers. There

is a negative trend for the total world imports, which reflects a significant decline in the demand for

ammonia in terms of international trading but not consumption. The figure also ranks the countries by

the largest importer in 2019, which reflects that India became the top importer as of 2019. Also, it is

important to note that the US is no longer the top importer of ammonia, which it mainly imported in the

past from Canada. On the other hand, the US increased the ammonia exports by 78 percent in five years,

where the main buyers are Mexico, Chile, South Korea, and Morocco.

July 2020


Figure 2.15: Top 15 Ammonia Importers Between 2015-2019

Source: Data from ITC, 2019. Figure by CERI

The top five exporters with the highest market share for ammonia are Saudi Arabia (28.2 percent), Russia

(15.9 percent), Trinidad and Tobago (14.2 percent), Indonesia (7.4 percent), and Canada (5.5 percent).

The annual growth rate for exporters between 2015-2019 shows that Saudi Arabia has the highest annual

growth in 5 years as an exporting country. In contrast, the other leading producers did not export

significant quantities in terms of dollar value. For example, Russia’s annual growth remained steady,

Indonesia had 4 percent growth, Trinidad and Tobago had 12 percent decline, and Canada had 16 percent

decline in the value of the ammonia exports (ITC 2019).

In general, ammonia imports did not increase except for Bulgaria and Bangladesh, where the dollar value

for imports is relatively low. There is a significant decline in ammonia imports in the US (25 percent), India

(3 percent), and the Republic of Korea (3 percent). This means that the ammonia market is very

competitive and will be very tight when the US production meets its own domestic market and competes

in other markets such as Mexico, which reduced imports from Trinidad and Tobago and recently increasing

the imports from the US (ITC 2019).

The average distances to demand markets are different compared to methanol. For example, the average

distance from the source to destination is 3748 Km to India, 8462 Km to South Korea, 5884 Km to China,

5790 Km to Taipei, 2538 Km to Thailand, 4734 Km to Bangladesh, and 5342 Km to Japan. The average

distances to European markets are even shorter, which reflects the trading within the European Union.

The South American top importers mainly buy from the US and Trinidad and Tobago. On the other hand,

the average distances are longer for the North African market, such as Morocco, which imports mainly

from Russia, Trinidad and Tobago, and the US (ITC 2019).

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As stated earlier, the tariffs for the European countries are fixed at 1.4 percent. Bangladesh has the highest

tariffs at 9.8 percent, China at 6.6 percent, and India at 6 percent. Brazil and Chile's tariffs are 3.8 and 3.2

percent, respectively. Ammonia import tariffs in Morocco is 2 percent. While other top importers have

insignificant tariffs (ITC 2019).

Ethylene

The total value of the world’s ethylene imports is $7.6 Billion in 2019. Figure 2.16 below shows the dollar

value for ethylene imports over the last five years for the top 15 countries. There is a positive trend

between 2015-2018, which shows annual growth for the world ethylene imports, depicting the increase

in demand for this market. The two main markets are Asia and Europe.

Figure 2.16: Top 15 Ethylene Importers Between 2015-2019


The top five exporters of ethylene are the Netherlands (15.2 percent), South Korea (14.1 percent), UK

(11.5 percent), Japan (10 percent), and Singapore (6.3 percent). It is important to note that CERI Study

181 explored the potential for North America compared to other olefins (ethylene and propylene)

suppliers and addressed Canada’s potential. The cheaper feedstock and its lower emissions profile are the

key strengths for North America. However, the average distance to importing countries is significantly

longer than the other top exporters. It is important to note that the US is ranked the 9th with 3.1 percent

market share, while Canada has no significant market share in the ethylene exports (ITC 2019).

The annual growth rate for exporters between 2015-2019 shows an increase for other countries such as

India and Hong Kong and other exporters who still have negative trade balances, including Hungary, Spain,

Sweden, and China.

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The top ethylene importers are China, Belgium, and Germany. Annual growth in imports over the past five

years declined by 28 percent in China, 12 percent in Belgium, and 7 percent in Germany. It is important

to note that there are many countries with a negative trade balance, which may highlight feedstock supply

opportunities if they choose to develop or grow domestic capacity in the long term.

The gaseous state of ethylene makes handling and shipping more complex than for methanol or ammonia.

For this reason, it is not cost-effective to ship the product over long distances and import data indicate

relatively shorter distances for ethylene shipments. However, converting ethylene to a polymer such as

polyethylene makes for easier handling and transport to distant destination markets.

The tariffs for ethylene are also low. For example, the average tariff for ethylene in China is 3.2 percent

and no other major importers have tariffs on this commodity.

Propylene

The total value of the world’s propylene imports is $7.6 Billion in 2019. Figure 2.17 below shows the dollar

value for propylene imports over the last five years for the top 15 countries. There is a positive trend

showing an increase in the demand for propylene. Again, the main demand markets are Asia, Europe, and

the Americas (Colombia and the US).

The top five propylene exporters with the highest market shares are South Korea (21.5 percent),

Netherlands (11.6 percent), Japan (10.9), USA (9.4 percent), and Taipei (7.8 percent). Canada is ranked

the 9th with 2.8 percent market share. It is important to note that North America has better market shares

in propylene exports due to the availability of the propane dehydrogenation (PDH) projects, which

combine different economic factors such as very cheap feedstock, the highest propylene yield, and the

lowest emission profile (CERI Study 181). Again, the main hurdle would be the distance to demand

markets (ITC 2019).

The annual growth rate for the exporters between 2015-2019 shows a significant increase for China and

Malaysia despite their negative trade balance. On the other hand, European countries such as Sweden,

Austria, and Finland had a relatively high five years annual growth in exports, which might indicate that

the European market will be fulfilled within the European Union countries.

July 2020


Figure 2.17: Top 15 Propylene Importers Between 2015-2019


Since propylene is in gaseous state at room conditions, upgrading it to other products such as

polypropylene, acrylonitrile, oxo chemicals, propylene oxide, cumene, isopropyl alcohol, acrylic acid eases

the logistical challenges of trading especially over long distances.

The average tariffs for propylene imports in China are 3.2 percent. On the other hand, there are no

reported tariffs for other major propylene importers.

Opportunities for Canada at Destination Markets

Figure 2.18 shows the dollar value of different value-added products based on the world’s imports and

their linear trends. The ranking of value-added products from a global trading perspective would be

methanol, ethylene, propylene, and ammonia. The ranking of the products is critical for decision making

regarding the demand potential for each product post-2020.

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July 2020


Figure 2.18: World Imports Value of Petrochemicals

Source: Data from ITC,2019. Graph by CERI

Methanol

Canadian methanol imports and exports occur across a fairly wide range of countries as trading partners.

However, the main suppliers to Canada are Trinidad and Tobago, Venezuela, and the US. On the other

hand, the primary importer for methanol from Canada is the US, followed by China and Cuba. Figure 2.19

shows the value of imports/exports from 2015 to 2019.

Figure 2.19: Methanol Imports/Exports in Canada


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The amount of imports shows an opportunity for methanol production in Canada to fulfill the domestic

market’s needs. Also, it is important to note that Canadian producers must be prepared to compete

vigorously in the US as this country is increasing its methanol production capacity, which could eventually

diminish the Canadian producers’ market shares.

One option for Canada is to increase market share in the Chinese market, which is a rapidly growing

market and has a high potential to increase the total world consumption of methanol. Another option for

Canada is to recognize the impact of the IMO 2020 requirements and capture a greater volume of the

market to provide ships with low sulphur marine fuel.

It has been observed that methanol is a reasonable option as a marine fuel, which has more advantages

compared to LNG in terms of engine retrofitting and the related costs. There is a geographic advantage

for Canada to be able to supply clean marine fuel for three oceans.

Ammonia

Ammonia exports are focused on the US market. Insignificant amounts go to Netherlands, Australia, and

Cuba. On the other hand, imports are very low, mainly from the US, and an insignificant amount from

Portugal, Belgium, Germany, and Japan. Figure 2.20 shows the decline in Canadian exports, which is

mostly impacted by the reduction in US imports.

Figure 2.20: Ammonia Imports/Exports in Canada

Source: Data from ITC. Figure by CERI

Therefore, Canadian producers should investigate trading options with other global importers in other

markets, especially the ones already familiar with importing from North American. As such, South

American importers offer potential and other possible options like South Korea, Morocco, Ireland, Israel,

and Belgium, all of which have a negative trade balance on the product and imports from North America.

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India is the top ammonia importer, which currently mainly imports from the Middle East, Asia, and Europe,

including Saudi Arabia, Qatar, Indonesia, Egypt, Ukraine, and Iran. It is important to note that geographic

location, feedstock availability and price, and environmental regulations can be important factors

affecting the competitiveness of ammonia trading.

Ethylene

Canadian ethylene imports and exports take place in North America, specifically with the US, without

any other significant records with other countries. The ethylene trading declined after 2015, as shown in

Figure 2.21, mainly due to the increased capacities of steam crackers in the US, which fulfilled the US

domestic market and increased the US trade balance by around 70 percent.

Figure 2.21: Ethylene Imports/Exports in Canada


Alternative major markets for Canada could include France, Sri Lanka, Germany, and Mexico where there

are negative trade balances and growing demands.

The second possible option is to explore trading with other top importers who ultimately trade with the

other North American competitors. The possible market would be with China and Taipei in Asia and

Belgium, Spain, and Netherland in Europe.

Propylene

Same as ethylene, propylene exports are mainly to the US, with insignificant amounts to Hong Kong.

Figure 2.22 shows a slight decline in exports, even though there is a global demand for propylene and its

derivatives.

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Figure 2.22: Propylene Imports/Exports in Canada

Source: Data from ITC. Graph by CERI

Canada’s possible options are major importers such as China and Taipei in the Asian markets, and

Belgium, Germany, Spain, Netherland, Italy, and Austria, in the European markets.

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Chapter 3: Methodology

Modelling Framework

CERI used an Integrated Project Economics Model (IPEM) that combines process, microeconomic and

macroeconomic modules to provide a full economic assessment of the impacts of investing in both

greenfield and brownfield petrochemical plants producing methanol, ammonia, ethylene, and propylene

in Alberta, Saskatchewan, and Newfoundland and Labrador. The model components in IPEM are

interdependent, so that the overall assessment results reflect the integrated nature of the decision-

making process based on the routines performed at each module, which informs the other modules.

Figure 3.1 shows the IPEM workflow, showing the major inputs to the modules and their outputs.

Figure 3.1: Integrated Project economic model (IPEM) workflow

IPEM’s process module uses industry data for various process technologies, facility designs, and operating

conditions to perform energy and material balances. The energy balance is used to quantify process

energy requirements, including heat (fuel consumption and steam use) and electricity. The material

balance accounts for feedstock consumption and generation of products, including emissions from the

process.

The microeconomic model uses project development and operation information, in addition to the

process module’s results, to perform project cash flow analysis and calculate the breakeven price of a

product for either greenfield (supply cost) or brownfield (cash cost) plant. Supply cost is usually defined

as the constant-dollar breakeven price of the product at which all expenditures – including the capital,

operating, royalties and taxes – are recovered together with a specified return on investment. Cash cost

assumes that all CAPEX (including the CAPEX financing cost) has been recovered so that only the

July 2020


production cost at the specified return on investment needs to be covered. IPEM calculates the breakeven

prices on both constant-dollar and inflation-adjusted bases.

Macroeconomic impacts such as direct and indirect impacts on GDP, tax revenue, job creation, and

salaries/wages are estimated at both provincial and national levels within the macroeconomic module of

IPEM. Data on sectoral multipliers are used to quantify the impacts on the macroeconomic variables

within the province of locale and other provinces for all dollars spent by the project across economic

sectors involved during the construction or operation of the plant.

Detailed industry data covering various technologies, facility designs and operating performances were

used to create two project investment cases: Reference Business Case (RBC) and Competitive Business

Case (CBC). The RBC represents a lower bound on the attributes of facility design and less favourable

investment economic parameters as reported by industry data, whereas the CBC represents an upper

bound on the facility attributes and more favourable investment economics. Facilities with attributes

between these two categories can be assessed by updating the facility design attributes and/or the

investment economics attributes within IPEM. Table 3.1 shows the definitions of the facility design and

investment economic attributes describing the two project investment business cases.

Table 3.1: Facility-level Investment Business Cases

Attribute Reference Business

Case

Competitive Business

Case

Facility Size Smaller Bigger

Process Efficiency Lower Higher

Project Funding Debt Equity

Carbon Tax Yes No

Feedstock Demand and Product Supply Scenarios

From the project investment business cases, Canadian growth opportunities for production of the

products are assessed based on locating the production plants within provinces where the best economic

impacts can be gained. This is done by adopting the CBC investment option with potential updating of the

attributes – particularly, facility size – in accordance with the product demand growth trajectory

anticipated in each forecast scenario. To this effect, three product supply scenarios are designed and

assessed as follows:

Business As Usual (BAU) Scenario; this mirrors the existing Canadian market flows of the

product in which domestic and export demands are met by domestic supply and imports.

Historical annual demand growth rate is then applied to the supply to estimate future supply

need.

�� + �� = �� + ��

Medium Supply Growth (MSG) Scenario; there are no imports of the product into Canada in

this scenario. The domestic supply comprises of the BAU domestic supply and imports, in

July 2020


addition to 1 percent global export market gain. Historical annual demand growth rate is also

applied to the supply estimate to forecast future production opportunities.

�� + �� = ��

�� = �� + �� + 1% ��

High Supply Growth (HSG) Scenario; which is similar to the MSG scenario but here, the

additional global export market share (which is incremental to exports in the BAU scenario) is

increased by 2 percent. Historical annual demand growth rate is also applied accordingly.

�� + �� = ��

�� = �� + �� + 3% ��

General Modelling Assumptions:

- All monetary values are reported in 2019 US dollars;

- Average 2019 feedstock prices are applied with AECO gas prices used for Alberta and

Saskatchewan, whereas the Dawn price is used for Newfoundland and Labrador which produces

associated gas offshore. The average 2019 naphtha price in Western Canada is used for Alberta

and Saskatchewan while the price in eastern Canada is assigned to Newfoundland and Labrador;

- Newfoundland and Labrador have better access to naphtha due to its location where naphtha can

be accessed from the rest of eastern Canada (which has about 65 percent Canada’s refining

capacity) or the international market;

- Industrial electricity rates in each province during 2019 is applied accordingly;

- CAPEX and OPEX for naphtha crackers are allocated to each co-product by the mass yields of all

high value chemicals;

- Feedstock prices are inflated at a yearly rate of 2 percent;

- For debt-funded projects, the financing cost is assumed to be 3.5 percent;

- Discount rate (nternal rate of return) of 10 percent is used for all products and plant locations;

- Construction cost location factors: Alberta (1.05), Saskatchewan (1.05), Newfoundland and

Labrador (0.98);

- Accelerated depreciation schedule based on the Canadian Revenue Agency’s capital cost

allowance rate for Class 53 is adopted;

- Capital cost is split into depreciable and non-depreciable (owner’s cost) components at 90 percent

and 10 percent, respectively;

- Macroeconomic sectoral allocation of capital expenditure for a new petrochemical plant is based

on a 70 percent and 30 percent distribution between the petrochemical plant construction sector

and the petrochemical industry.

Table 3.2 below illustrates some of the general modelling assumptions, and further detailed information

on assumptions and modelling input data are available in Appendices A – F.

July 2020


Table 3.2: Some General Economic Modelling Assumptions and Input Data

Input Value

OPEX inflation 2%

Feedstock price inflation 2%

Discount rate 10%

Interest rate 3.5% (WACC=4.5%)

Utilization factor 70% (Year 1), 80% (Year 2), 95% (Other)

CAPEX allocation 20% (Year 1), 50% (Year 2), 30% (Year 3)

Construction period 3 Years

Operating period 27 Years

Corporate tax AB (11%, 10%, 9%, 8% - all other years), SK

(10%), NL (15%), Canada (15%)

July 2020


Chapter 4: Results and Discussion Two investment business cases were defined in the methodology section as Reference Business Case

(RBC) and Competitive Business Case (CBC) to bracket the results of our assessment with a lower and

upper limits of performance of all investment decisions on the project financing and petrochemical

processing technology attributes, respectively. This provides for a concise analysis of the results for this

report, although IPEM assesses all the combinations of choices for financing and facility design attributes.

All the possible options arise from publicly available economic and process data on the four products

assessed in this study. CERI will make other results – not presented here - available through the Tableau

Dashboards on our website.

Supply Cost and Cash Cost of Products

Supply costs were estimated for greenfield facilities that produce methanol and ammonia using natural

gas feedstock and ethylene and propylene using naphtha as feedstock in the three provinces of Alberta,

Saskatchewan, and Newfoundland and Labrador. Cash costs were also estimated for hypothetical

brownfield plants producing the same products in those provinces. IPEM uses an explicit solution method

to calculate supply cost and cash cost in either constant-dollar or inflated-dollar. The latter would indicate

the cost in current-dollar value if a specific inflation rate or function were expected over the project’s

lifetime. Supply costs were calculated using a 10 percent (real) annual discount rate, which is equivalent

to a 12 percent (nominal) annual return on investment based on an estimated average inflation rate of 2

percent per annum.

Figures 4-1 and 4-2 show the RBC and CBC supply costs for all products in the provinces in both constant

and inflated dollars. As expected, supply costs are lowest in CBC projects and highest for RBC projects.

Inflated dollar supply cost for ammonia in the three provinces in the year 2020 ranges between $479 to

$535 per tonne for RBC and $313 to $360 per tonne for CBC. Inflated dollar supply cost for methanol in

the three provinces in the year 2020 ranges between $299 to $346 per tonne for RBC and $194 to $237

per tonne for CBC. Inflated dollar supply cost for ethylene and propylene in the three provinces in the year

2020 ranges between $1244 to $1421 per tonne for RBC and $1013 to $1165 per tonne for CBC. In both

cases, ammonia and methanol are cheaper in Alberta, while ethylene and propylene are cheaper in

Newfoundland and Labrador. This can be explained by the lower cost of the respective feedstocks and

their availability in Alberta (natural gas) and Newfoundland (naphtha - in eastern Canada in general).

Based on location factors, construction costs are also higher in Alberta than in Newfoundland.

Figure 4.3 compares the constant-dollar supply costs of the products for the two business cases. Similar

trends as in the inflated-dollar mode of supply cost are maintained with Alberta offering the lowest supply

cost for methanol and ammonia. In contrast, Newfoundland has the lowest cost for ethylene and

propylene from naphtha cracking. Ammonia supply cost in Alberta ranges from $394 per tonne in CBC to

$602 per tonne in RBC. Methanol supply cost in Alberta ranges from $244 per tonne in CBC to $366 per

tonne in RBC. Ethylene and propylene supply costs in Newfoundland ranges from $1457 per tonne in CBC

to $1769 per tonne in RBC. The aggregated effects of debt funding, lower process yields, higher process

energy requirements, carbon tax, and smaller economies of scale make the supply cost of products higher

July 2020


in the RBC investment option relative to the CBC option. IPEM also quantifies the supply cost of products

for other project investment and facility design choices, which bring the final supply cost numbers to a

value between the CBC (lower bound) and RBC (upper bound) values.

While supply cost captures the all-in cost of an investment at a specified rate of return, cash cost estimates

assume that capital expenditures of the facility have been fully recovered – which can be likened to the

breakeven price of a product from a brownfield facility post payback period. Figure 4.4 compares cash

costs of the products in the three provinces for RBC and CBC projects. For RBC projects, ammonia cash

cost is lowest in Alberta at $295 per tonne and highest in Newfoundland at $363 per tonne. Methanol

cash cost is also lowest in Alberta at $219 per tonne and highest in Newfoundland at $286 per tonne.

Figure 4.1: RBC Constant and Inflated Dollar Supply Cost of all Products in the Provinces

July 2020


The cash cost of ethylene and propylene high-value chemicals from naphtha cracking is estimated to be

lowest for a plant located in Newfoundland at $1239 per tonne and highest for a Saskatchewan plant at

$1456 per tonne. For CBC projects, ammonia cash cost is also lowest in Alberta and highest in

Newfoundland at $214 per tonne and $272 per tonne, respectively. Methanol cash cost is also lowest in

Alberta at $147 per tonne and highest in Newfoundland at $200 per tonne. Ethylene and propylene

naphtha cracking co-products have their lowest cash cost for a Newfoundland plant at $1037 per tonne

and the highest cash cost for a Saskatchewan plant at $1224 per tonne. The difference between supply

cost and cash cost accounts for capital investments and project financing. The smaller the difference

between the two, the higher the predominance of feedstock cost on breakeven prices.

Figure 4.2: CBC Constant and Inflated Dollar Supply Cost of all Products in the Provinces

July 2020


Figure 4.3: Comparison of Constant-Dollar Supply Costs for RBC and CBC Project Investments

Figure 4.4: Comparison of Cash Costs for RBC and CBC Project Investments

0

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AB SK NL AB SK NL

Reference Business Case (RBC) Competitive Business Case (CBC)

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Supply Cost - Constant Dollar

Ammonia Ethylene Methanol Propylene

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RBC CBC

July 2020


Cumulative Cashflow and Payback Period

The time it takes from the end of the investment period to the breakeven point or beginning of profit

period is the payback period of the investment. Generally, equity-financed projects have shorter payback

periods due to the avoidance of additional financing charges. Figures 4-5 and 4-6 indicate the payback

period of investment for the RBC and CBC projects, respectively, when cumulative cash flows are

calculated using the constant-dollar supply cost model. Due to the higher efficiency of CBC investment

decisions, their cumulative cash flows are higher than those of RBC projects, in addition to a shorter

payback period relative to RBC projects. Ethylene and propylene CBC projects have the shortest payback

period of 5 years, whereas ammonia and methanol have a year longer payback period of 7 years. RBC

projects tend to have a slightly longer payback period, but the payback period does not vary significantly

by the province of the location of the project.

Figure 4.5: Cumulative Cashflow and Payback Period of Investment for the RBC Projects (US$)

CBC’s cumulative cashflow of ammonia and methanol in the three provinces ranges from $2.1 to $2.5

billion. Accordingly, cumulative cashflow of ethylene ranges from $0.8 to $1.3 billion, whereas propylene

ranges $0.4 to $0.7 billion across the three provinces. When cash flows are calculated on a constant-dollar

supply cost basis, for products with high sensitivity to feedstock price, net revenue can be estimated as

negative in the future due to the effect of feedstock price (or OPEX) inflation in the supply cost model.

This is why cumulative cashflow profiles of ethylene and propylene are convex-shaped for both RBC and

CBC projects. Perhaps, it is a matter of methodological preference, considering that it is common for all

variable operating expenditures for various inputs into a supply cost model to be inflated at a specific rate.

July 2020


However, this can be avoided and consistently maintained by either providing all inputs to the model in

constant-prices or applying the same inflation rate to the breakeven price being calculated, so that supply

cost is then calculated on inflated-dollar (instead of constant-dollar) basis.

Figure 4.7 shows the same CBC cumulative cashflow plot for an inflated-dollar supply cost model. The

payback period estimate would usually be longer than when determined on a constant-dollar supply cost

basis because the inflated-dollar supply cost would be less than the constant-dollar supply cost in the

earlier years, as it gradually ramps up with compounding of the inflation factor over operating life of a

project. From the figure, the payback period of an ammonia plant in any of the provinces of Alberta,

Saskatchewan, or Newfoundland is estimated to be about nine years. The estimated payback period for

the methanol project is about eight years. Similarly, it would take about eight years to recover the costs

of investing in a new naphtha cracker under a CBC project option.

Figure 4.6: Cumulative Cashflow and Payback Period of Investment for the CBC Projects (US$)

July 2020


Figure 4.7: Cumulative Cashflows of CBC Projects Based on Inflated-dollar Supply Cost

July 2020


Macroeconomic Impacts of Investment

IPEM incorporates inter-provincial macroeconomic impact multipliers from Statistics Canada to create

economic sectoral Input-Output effect of new petrochemical project investments on GDP, tax revenue,

job creation, and salaries/wages both provincially and nationally. The macroeconomic model estimates

the direct and indirect effects of shocks to economic sectors where the money is spent as a result of the

new value-add project investment. Direct impacts account for the growth in demand for industries that

expand production in order to satisfy the increased demand from the sectors that received the shock.

Indirect impacts result from the affected industries purchasing additional inputs from other firms. IPEM

also estimates temporary and permanent impacts during project construction and operation periods,

respectively.

National GDP Impacts

Figures 4-8 and 4-9 show the annual national GDP impacts on the two investment options (RBC and CBC)

during construction and operation periods. The RBC projects’ GDP contributions are generally smaller than

CBC projects due to the bigger facility size in the case of CBC requiring higher capital investment during

construction and more operating expenditure following their higher throughput capacity. Annual impacts

are obtained by taking average during the construction period – for temporary impacts and during the

first ten years of the operating period – for permanent impacts over the facility’s lifetime. For RBC

projects, temporary GDP impact is highest for ethylene investment, and permanent impact is highest for

an ammonia plant. However, ethylene and propylene are co-products of a naphtha cracker, their impacts

are additional. The impact of a project in Alberta or Saskatchewan is slightly higher than that of the same

project in Newfoundland.

Figure 4.8: Direct and Indirect Impacts on Canadian GDP by RBC Projects

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90

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Construction Operation

An

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Imp

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(US$

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July 2020


For CBC projects, olefin cracker and methanol investments have more GDP impacts than ammonia during

the construction period. In contrast, ammonia production has a higher impact during the operating life of

the plants. The annual permanent GDP impact of a CBC ammonia plant has the same value of $41 million

irrespective of the plant’s location among the three provinces investigated here. Similarly, the operational

impacts of ethylene cracker investments are the same for the provinces at $27.6 million. For methanol

and propylene, operational GDP contributions are $16.1 million and $13.2 million, respectively. Direct and

indirect impacts at the individual provincial levels are also computed by IPEM, but for the sake of brevity,

further detailed results are available in Appendix E.

Figure 4.9: Direct and Indirect Impacts on Canadian GDP by CBC Projects

Tax Revenue Impacts

Federal and provincial taxes are generated as the petrochemical plant is operated, and produced goods

sold to the users. IPEM generates tax revenue impacts, including direct and indirect sources at just the

provincial level or the combined provincial and federal taxes. In general, income taxes are considered

direct taxes. In contrast, expenditure taxes such as GST, HST, PST, and all taxes deductible by corporations

for income tax purposes (such as property taxes) are treated as indirect tax. Figure 4.10 shows aggregate

annual tax revenue with provincial and federal taxes from direct and indirect sources resulting from

investments in the RBC and CBC projects.

RBC projects generate smaller tax revenues relative CBC projects due to their smaller facility size.

Furthermore, provincial tax rates vary, and that is reflective in the tax revenue multipliers deployed in the

macroeconomic model. For both project types, ethylene production offers the highest tax revenue

impact, while ammonia production has the lowest impact. For CBC projects, annual direct and indirect tax

revenue impact from ethylene production is expected to be $26.1 million if the project is located in

Alberta, $26.2 million in Saskatchewan, and $22.3 million in Newfoundland and Labrador. The tax revenue

impact for ammonia production would be about $6.1 million in Alberta, $6.2 million in Saskatchewan, and

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July 2020


$7.4 million in Newfoundland and Labrador. For methanol, the expected annual tax revenue is $8.1 million

in Alberta, $8.3 million in Saskatchewan, and $10.6 million in Newfoundland and Labrador.

Figure 4.10: Direct and Indirect Impacts on Canadian (Provincial & Federal) Tax Revenue

Employment and Compensation Impacts

Permanent (operating period) employment numbers supported by a new investment were estimated

using initial results in person-years, which were converted to employment numbers by assuming that each

employee would work 40-hour weeks each year over the 27-year operating lifetime of each plant. A similar

assumption was applied to estimate the number of temporary (construction period) jobs supported by

new investment, albeit during a much shorter construction period of 3 years.

IPEM can separately estimate direct jobs, indirect jobs, and direct and indirect jobs supported by a new

project at either provincial or national levels. In this section, we compare direct and indirect permanent

job impacts of the two project types presented in this report. In the following section on product supply

scenarios, only direct job impact of each facility investment is discussed within the supply scenarios. Some

further detailed results have been made available in Appendix E, and interested readers will be able to

query the results database via CERI Dashboards on our website.

Figure 4.11 compares direct and indirect permanent job impacts of RBC and CBC projects. Job impacts are

higher for CBC than RBC projects due to the difference in facility design and project financing. Ammonia

plant investment and production have the most impact on the number of jobs supported by the new

petrochemical projects. Ammonia production plant could support about 1500 jobs for an RBC project and

3000 for a CBC project. Methanol production should support almost the same number of jobs (about 600),

as is supported due to propylene production for RBC projects. However, a CBC methanol plant is expected

to support more jobs than a CBC propylene plant; with total direct and indirect job numbers of about 1180

and 970, respectively.

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July 2020


Figure 4.11: Direct and Indirect Permanent Jobs Supported by New Projects

CERI calculates the pay rate by dividing the salaries/wages calculated with the macroeconomic module in

IPEM by the estimated employment numbers based on a conversion from the original reporting unit of

person-years. Direct and indirect pay rate represents the ratio of direct and indirect salaries/wages

impacts with the corresponding job numbers.

As shown in Table 4.1, the direct and indirect pay rate does not change significantly between the

petrochemical products and project types. However, pay rates are higher at the provincial level than

national as more variety in the categories of firms that provide inputs into the petrochemical sector are

reached. The more the difference in the category of providers, the more the variety in pay rates of the

collective of firms, which lowers national level pay rate impacts relative to the provincial.

Table 4.1: Average Pay Rate per Employment for Direct and Indirect Jobs Supported

Project Type Pay Rate (US$/Month)

Canada Provincial

Reference Business Case (RBC) 4086 4464

Competitive Business Case (CBC) 4086 4464

Regional Price Competitiveness of Products

Publicly reported 2019 data on price ranges for the four products in North American, European, and Asian

markets is compared to the free on board (FOB) origin price ranges for the two business cases (RBC and

CBC) evaluated in this report. Detailed information price is provided in Appendix F. The lower range of the

price in each case represents the cash cost for a brownfield facility with fully recovered CAPEX and the

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July 2020


upper range represents the supply cost for a greenfield facility which has to recover all CAPEX investments

and financing costs along with achieving a 12 percent (nominal) return on investment.

Compare the most competitive breakeven price estimates for each product in Canada using supply cost

(upper limit) and cash cost (lower limit) for the province with the best competitive investment option for

the product among the three Canadian provinces assessed in this study. We observed from earlier results

that methanol and ammonia are most competitive for facilities located in Alberta, whereas ethylene and

propylene co-products from naphtha cracking are most competitive for a plant in Newfoundland and

Labrador.

In Figures 4-1 to 4-4, CERI’s estimate of lower and upper limits of respective FOB origin prices for

brownfield and greenfield RBC and CBC projects, optimally located in Canada at the province where FOB

prices of the product is lowest in comparison to the other provinces, is compared to the range of 2019

prices reported for the products in North America, Europe, and Asia.

Figure 4.1: Comparison of Regional Prices of Methanol to the Estimated RBC and CBC Breakeven Prices

Canadian methanol price for an RBC project is expected to be competitive in the three regions with FOB

origin price range of $219 to $366 per tonne, provided the landed cost is less than $442 per tonne in North

American regional markets, $410 per tonne in European markets, and $370 per tonne in Asian markets.

A greenfield CBC project will not only be competitive in all three regional markets but could also compete

with cash cost-priced suppliers in those markets, provided the landed cost is not more than $227 per

tonne. The estimated CBC plant’s FOB origin price range is between $147 to $244 per tonne.

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July 2020


Figure 4.2: Comparison of Regional Prices of Ammonia to the Estimated RBC and CBC Breakeven Prices

Canadian ammonia plant of the RBC type can be expected to be competitive in North American and Asian

regions on a cash cost basis, but not in Europe. However, the landed cost in North American markets

needs to be not more than $350 per tonne and not more than $340 per tonne in Asian markets. A

greenfield RBC type plant in Canada cannot compete for market share in any of these regions. For

Canadian CBC ammonia plant, the product is expected to be competitive on both supply cost, and cash

cost basis provided the landed cost in a North American market is not more than $350 per tonne, also not

more than $275 per tonne in European markets, and not more than $340 per tonne in Asian markets. FOB

origin price range for a CBC ammonia plant in Canada is estimated to be between $214 to $394 per tonne.

An RBC type naphtha cracking plant for ethylene production in Canada is unlikely to be competitive on

both cash cost and supply cost basis in any of the three regions of comparison. The estimated FOB origin

price range for such a plant is $1239 to $1563 per tonne. However, a CBC type naphtha cracker in Canada

producing ethylene is not expected to be competitive in North American markets but may be able to

compete in Europe and Asia if the landed costs in those markets is not more than $1220 per tonne and

$1176 per tonne, respectively. FOB origin price range for the CBC project is between $1037 to $1273 per

tonne.

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July 2020


Figure 4.3: Comparison of Regional Prices of Ethylene to the Estimated RBC and CBC Breakeven Prices

Figure 4.4: Comparison of Regional Prices of Propylene to the Estimated RBC and CBC Breakeven Prices

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July 2020


RBC type propylene production in Canada will not be competitive in Europe and Asia in supply cost nor

cash cost terms. However, it is likely to be competitive with the marginal propylene suppliers in North

American markets if the product from Canada is sold at slightly above cash cost basis with a landed cost

at the destination market not exceeding $1345 per tonne. FOB origin price for the RBC plant naphtha

cracking propylene ranges between $1239 to $1563 per tonne. A CBC type propylene cracker plant in

Canada is expected to be competitive in North America on both supply cost and cash cost, not competitive

in Asian markets at all, but only competitive in European markets on slightly above cash cost basis if the

FOB destination price does not exceed $1115 per tonne. FOB origin price range for the CBC propylene

plant is between $1037 to $1273 per tonne. However, in North American markets, FOB destination price

needs to stay below $1345 per tonne for competitiveness.

Effect of Carbon Tax on Canadian Supply and Cash Costs

Figure 4.5 shows the impact of a federal carbon tax schedule on supply costs of products for both the RBC

and CBC projects. Recall that the RBC supply and cash costs already include carbon tax by the design of

the business cases, as illustrated in the methodology section. Therefore, the carbon tax contributions

shown here are only additional on the CBC breakeven prices presented earlier.

There is about a $5 per tonne difference in carbon tax contributions between RBC and CBC investments.

For a CBC plant, breakeven price of ammonia increases by about $32 per tonne. Similarly, breakeven price

of methanol increases by around $27 per tonne, whereas for ethylene and propylene it increases by about

$40 per tonne. While carbon tax does not change the economics significantly relative to other

components of the supply and cash costs, it does affect the final breakeven prices and could determine

FOB destination competitiveness of the product.

July 2020


Figure 4.5: Effect of Canadian Federal Carbon Tax Schedule on the Breakeven Prices

Product Supply Scenarios and Economic Impacts

Product supply scenarios are developed based on the CBC project investment cases for the products at

the Canadian province where the supply cost is most competitive. For instance, the production of

methanol and ammonia are most competitive in Alberta on a supply cost basis, whereas ethylene and

propylene are more competitive in Newfoundland and Labrador (and eastern Canada) primarily due to

naphtha availability and pricing in the eastern Canada relative to western Canada.

Three supply scenarios for the four basic petrochemical products were developed as described in Chapter

3 on methodology, to capture current Business As Usual (BAU), Medium Growth Scenario (MGS), and High

Growth Scenario (HGS). Historical demand growth rates were applied to generate estimates of future

supplies of the products under each scenario for domestic and export markets from the Canadian

petrochemicals industry, over the period from 2020 - 2050. All forecasts are based on the CBC type

production plant development. The most competitive supply costs for domestic production of the

products in Canada also result in the most economic impacts.

The BAU scenario maintains current market conditions in Canada where there is domestic demand and

export demand, but the domestic demand is met by domestic production in addition to imports. Table 4.2

shows the economic impacts of the BAU scenario where methanol production capacity is expected to

grow by 1.76 MTPA by the end of the forecast period, reaching 2.34 MTPA by 2050 with total feedstock

demand of 0.26 bcf per day of natural gas. This will contribute to economic impacts amounting to an

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July 2020


annual GDP increase of $107.02 million by 2050, a tax revenue increase of $28.27 million, 103 direct

permanent job growth, and an increase in pay rate of $1.21 million relative to the current levels in the

Canadian petrochemical sector.

Under the same scenario, ammonia production capacity is expected to grow by 1.85 MTPA by the end of

the forecast period, reaching 7.19 MTPA by 2050 with total feedstock demand of about 0.58 bcf per day

of natural gas. This will contribute to economic impacts amounting to an annual GDP increase of $574.02

million by 2050, a tax revenue increase of $48.96 million, 551 direct permanent job growth, and an

increase in pay rate of $5.81 million.

Table 4.2: Economic Impacts of Product Supply in Business as Usual Scenario

Economic Impacts

BAU

Total GDP

Increase

(USD Million)

Total Tax

Increase

(USD Million)

Direct

Jobs

created

Total Pay

Increase

(USD Million)

Methanol 2020 - - - -

2030 5.69 0.88 16 0.46

2040 44.30 9.30 64 0.75

2050 107.02 28.27 103 1.21

Ammonia 2020 - - - -

2030 68.99 4.70 199 2.04

2040 261.22 20.49 376 3.83

2050 574.02 48.96 551 5.81

Ethylene 2020 - - - -

2030 134.10 53.41 386 4.27

2040 604.83 280.04 870 10.21

2050 1,528.16 777.57 1,466 18.35

Propylene 2020 - - - -

2030 15.77 5.38 45 0.61

2040 79.67 33.09 115 1.37

2050 204.22 96.83 196 2.50

BAU ethylene production capacity is expected to grow by 7.78 MTPA by the end of the forecast period,



annual GDP increase of $1.53 billion by 2050, a tax revenue increase of $0.78 billion, 1466 direct job

growth, and an increase in pay rate of $18.35 million. Propylene production is as a coproduct from the

naphtha cracker but will result in additional economic impacts of annual GDP increase of $204.22 million

by 2050, tax revenue increase of $96.83 million, 196 direct job growth, and increase in pay rate of $2.50

million.

July 2020


Table 4.3 shows the economic impacts of the MSG where methanol production capacity is expected to



an annual GDP increase of $262.99 million by 2050, a tax revenue increase of $82.57 million, 252 direct

job growth, and an increase in pay rate of $2.52 million. Under the same scenario, ammonia production

capacity is expected to grow by 1.94 MTPA by the end of the forecast period, reaching 7.46 MTPA by 2050


impacts amounting to an annual GDP increase of $0.72 billion by 2050, a tax revenue increase of $61.18

million, 689 direct job growth, and an increase in pay rate of $6.59 million.

Table 4.3: Economic Impacts of Product Supply in Medium Supply Growth Scenario

Economic Impacts

MSG

Total GDP

Increase

(USD Million)

Total Tax

Increase

(USD Million)

Direct

Jobs

created

Total Pay

Increase

(USD Million)

Methanol 2020 4.01 0.62 115 0.63

2030 50.34 10.90 145 0.97

2040 131.79 35.50 190 1.57

2050 262.99 82.57 252 2.52

Ammonia 2020 7.45 0.37 214 1.17

2030 122.33 8.31 352 2.69

2040 357.91 28.05 515 4.54

2050 718.59 61.18 689 6.59

Ethylene 2020 26.63 8.31 766 4.17

2030 426.14 171.52 1,226 9.40

2040 1,288.35 593.25 1,854 17.25

2050 2,748.08 1,384.92 2,636 28.00

Propylene 2020 15.08 4.76 434 2.36

2030 194.07 76.83 559 3.80

2040 513.16 231.80 738 6.13

2050 1,019.11 504.83 978 9.62

MSG ethylene production capacity is expected to grow by 10.27 MTPA by the end of the forecast period,





naphtha cracker but will result in additional economic impacts of annual GDP increase of $1.02 billion by

2050, tax revenue increase of $504.83 million, 978 direct job growth, and increase in pay rate of $9.62

million.

July 2020


Table 4.4 shows the economic impacts of the HSG where methanol production capacity is expected to



an annual GDP increase of $415.99 million by 2050, a tax revenue increase of $140.99 million, 399 direct

job growth, and an increase in pay rate of $3.98 million. Under the same scenario, ammonia production

capacity is expected to grow by 2.07 MTPA by the end of the forecast period, reaching 8.00 MTPA by 2050


impacts amounting to an annual GDP increase of $0.98 billion by 2050, a tax revenue increase of $84.34

million, 938 direct job growth, and an increase in pay rate of $8.15 million.

Table 4.4: Economic Impacts of Product Supply in High Supply Growth Scenario

Economic Impacts

HSG

Total GDP

Increase

(USD Million)

Total Tax

Increase

(USD Million)

Direct

Jobs

created

Total Pay

Increase

(USD Million)

Methanol 2020 6.39 1.23 184 1.00

2030 80.03 20.29 230 1.54

2040 208.95 62.80 301 2.48

2050 415.99 140.99 399 3.98

Ammonia 2020 14.91 0.85 429 2.34

2030 200.35 14.35 577 3.97

2040 522.11 41.95 751 5.96

2050 977.99 84.34 938 8.15

Ethylene 2020 48.62 15.66 1,399 7.62

2030 680.57 275.87 1,959 13.98

2040 1,891.42 871.36 2,722 23.52

2050 3,828.88 1,924.97 3,673 36.59

Propylene 2020 26.90 8.71 774 4.22

2030 336.63 135.50 969 6.46

2040 868.79 396.73 1,250 10.10

2050 1,693.17 844.49 1,624 15.56

HSG ethylene production capacity is expected to grow by 12.48 MTPA by the end of the forecast period,





naphtha cracker but will result in additional economic impacts of annual GDP increase of $1.69 million by

2050, annual tax revenue increase of $0.84 billion, 1624 direct job growth, and increase in pay rate of

$15.56 million.

July 2020


July 2020


Chapter 5: Conclusions In this study, CERI assessed the economic impacts of value-added petrochemical products produced in

Canada from oil and gas feedstocks. Four products were assessed, including methanol, ammonia, ethylene

and propylene, for new projects that could be sited in Canadian provinces with significant oil and gas

production. CERI identified the provinces of Alberta, Saskatchewan and Newfoundland and Labrador as

potential locations in Canada meeting this primary feedstock availalbiity criteria.

For the study, detailed data on petrochemical process technologies and investment economics were used

to develop an Integrated Project Economics Model (IPEM) which combines process, microeconomic and

macroeconomic models to perform economic impact assessments on either brownfield or greenfield

petrochemical plants. Among other things, IPEM is used to estimate feedstock requirements, productivity,

supply cost for greenfield plants, cash costs for brownfield plants, investment payback period, GDP

impacts of capital and operating investments, tax revenue impacts, employment impacts and

salaries/wages impacts.

Due to the many options of economic investment and operating technology decisions involved in choosing

the attributes of a new petrochemical plant (i.e., the plant design and project economics choices involved),

this report can only present some of our results for the sake of brevity. Further detailed results will be

made available through CERI’s Tableau Dashboards on our website.

Two project investment business cases were used to categorize the entire results into a best-performing

and worst-performing investment economic and plant design decisions for a new facility. The best-

performing case was referred to as the Competitive Business Case (CBC) and the worst-performing case

as the Reference Business Case (RBC). These two cases define the lower bound and upper bound on the

outcomes of the assessments performed in IPEM, and this allows us to bracket our findings accordingly.

Our analyses showed that when Canadian production is compared to other suppliers of same products in

regional markets in North America, Europe, and Asia on average 2019 FOB price basis, CBC type plants

sited optimally in Canada are competitive in most cases. However, RBC type plants in Canada are not

competitive in most cases. Furthermore, a CBC methanol or ammonia plant in Canada will be able to

compete for market share in regional markets in North America, Europe and Asia. A CBC naphtha craker

located optimally in Canada can only compete with the marginal suppliers of ethylene in Europe and Asia

if the shipping cost to the destination market is favourable. It would not be competitive in North American

markets for ethylene, which is driven mostly by gas-based feedstocks. The propylene co-product from the

same plant is not expected to be competitive in Asia but may be able to compete in North American

markets, and compete with marginal suppliers in Europe on slightly above cash cost basis if the FOB

destination is favourable.

The gas-based petrochemicals value chain appear to be more suitable and economically competitive for

Canada than the oil-based (naphtha) pathway. In short, it appears that petrochemical investments in

Canada should keep the focus on gas-based pathways. Already, a number of ongoing project

developments have done so. Oil-based pathways, such as naphtha, would require new refining capacities

July 2020


in Canada, which is quite unlikely on the radar due to economics and other reasons around the market

for the other refinery co-products. Economically competitive new projects can contribute to the Canadian

economy in many ways, which can be evaluated through their contributions to provincial and national

GDPs, tax revenue generation, job creation, and employee salaries/wages. CERI also assessed the

potential economic impacts of the CBC project type investments under three product supply scenarios,

including a business as usual (BAU), medium supply growth scenario (MSG) and high supply growth

scenario (HSG) covering the period from 2020 - 2050.

Focusing on the gas-based products under the BAU scenario, methanol production growth over the

forecast period will result in annual GDP impact increasing by $107.02 million by 2050, with a total tax

revenue increase of $28.27 million and 103 new direct jobs created at a total pay rate increase of $1.21

million relative to the current value for the Canadian petrochemical sector. Ammonia supply growth will

increase annual Canadian GDP impact by $574.02 million by 2050, with a total tax revenue increase of

$48.96 million and 551 direct jobs created at a total pay rate increase of $5.81 million.

Under the MSG scenario, methanol production growth over the forecast period will result in annual GDP

impact increasing by $262.99 million by 2050, with a total tax revenue increase of $82.57 million and 252

new direct jobs created at a total pay rate increase of $2.52 million. Ammonia's supply growth will increase

annual Canadian GDP impact by $0.72 billion by 2050, with total tax revenue increase of $61.18 million

and 689 direct jobs created at a total pay rate increase of $6.59 million.

For the HSG scenario, methanol production growth over the forecast period will result in annual GDP

impact increasing by $415.99 million by 2050, with total tax revenue increase of $140.99 million and 399

new direct jobs created at a total pay rate increase of $3.98 million. Ammonia supply growth will increase

the annual Canadian GDP impact by $0.98 billion by 2050, with a total tax revenue increase of $84.34

million and 938 direct jobs created at a total pay rate increase of $8.15 million.

Apart from these direct impacts, other indirect and induced impacts are driven by such investments within

the broader economic sectors interacting in some way with the petrochemical sector at both provincial

and national levels.

Based on the competitiveness of breakeven prices, the best locations in Canada for producing each of the

products can be identified as shown in Table 5.1. The lowest breakeven prices for methanol and ammonia

are in Alberta whereas the lowest prices for ethylene and propylene are in Newfoundland and Labrador.

For the gas-based products, ammonia has higher economic impacts compared to methanol. However,

there is limited opportunity to develop new ammonia capacity for export markets because most countries

are choosing to produce their ammonia locally due to its use in agriculture, and perhaps, self-sufficiency.

For the oil-based products, ethylene has higher economic impacts compared to propylene. However, the

BAU scenario for ethylene production would require more than double the existing refining capacity in

Canada in order to generate the naphtha feedstock that would be needed. The HSG scenario would

require more than three times the existing refining capacity in order to generate enough feedstock.

Currently, there are no new plans to develop further refining capacity in Canada.

July 2020


While value-added projects are assumed to drive local business activities by purchasing products and

services from local suppliers and employing local people in the production areas, in some cases, it may be

in a company's best interest or their only choice to procure goods and services from outside the province

during project development or operation. Some specific inputs to the production process may need to

come from outside a particular province or even outside Canada. Such out of area spending translates to

economic leakage and increased spill-over impact on other provinces or other countries, which may not

be captured in our macroeconomic model. Employment impacts in this study only indicate what the future

labour requirement may be – this study does not address labour market issues such as labour supply and

demand, availability and/or shortages. Future research will be needed to answer these more nuanced

labour market questions.

Also, future research could be beneficial in exploring value-add products from oil sands bitumen. This

report only touches on two such products (presented in Appendix G), but further technical analysis will

be required to understand the economics and market potential for bitumen-derived value-add products.

Table 5.1: Summary of Economic Impacts of Optimal Investments Under the Three Supply Scenarios.

July 2020


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July 2020


Appendix A: Economic Modelling Table A.1: Project Design and Cost of Investment Data

Province Feedstock Product

Capacity (metric ton/year) Yield (%) CAPEX (US$ Million) Fixed OPEX (US$ Million)

Bigger Smaller Higher Lower Higher Lower Higher Lower

AB Natural Gas Methanol 1,600,000 500,000 0.88 0.74 1020.00 400.00 19.60 9.57

AB Natural Gas Ammonia 800,000 300,000 0.80 0.71 950.00 500.00 50.00 25.00

AB Naphtha Ethylene 696,000 336,000 0.77 0.68 1080.00 576.00 33.68 20.32

AB Naphtha Propylene 333,500 161,000 0.77 0.68 517.50 276.00 16.14 9.74

SK Natural Gas Methanol 1,600,000 500,000 0.88 0.74 1020.00 400.00 19.60 9.57

SK Natural Gas Ammonia 800,000 300,000 0.80 0.71 950.00 500.00 50.00 25.00

SK Naphtha Ethylene 696,000 336,000 0.77 0.68 1080.00 576.00 33.68 20.32

SK Naphtha Propylene 333,500 161,000 0.77 0.68 517.50 276.00 16.14 9.74

NL Natural Gas Methanol 1,600,000 500,000 0.88 0.74 952.00 373.33 19.60 9.57

NL Natural Gas Ammonia 800,000 300,000 0.80 0.71 886.67 466.67 50.00 25.00

NL Naphtha Ethylene 696,000 336,000 0.77 0.68 1008.00 537.60 33.68 18.97

NL Naphtha Propylene 333,500 161,000 0.77 0.68 483.00 257.60 16.14 9.09

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Table A.2: Process Energy Requirements and Pricing Data

Province Feedstock Product

Fuel Use (GJ/metric ton)

Power Use (GJ/metric ton) Feed Price

(US$/metric ton)

Fuel Price (US$/metric

ton)

Electricity Price (US$/metric

ton) Higher Lower Higher Lower

AB Natural Gas Methanol 13.8 11.6 0.7 0.3 88.5 88.5 16.92

AB Natural Gas Ammonia 15.6 13.5 0.5 0.3 88.5 88.5 16.92

AB Naphtha Ethylene 14.6 13.1 0.9 0.3 712.9 712.9 16.92

AB Naphtha Propylene 14.6 13.1 0.9 0.3 712.9 712.9 16.92

SK Natural Gas Methanol 13.8 11.6 0.7 0.3 88.5 88.5 25.09

SK Natural Gas Ammonia 15.6 13.5 0.5 0.3 88.5 88.5 25.09

SK Naphtha Ethylene 14.6 13.1 0.9 0.3 712.9 712.9 25.09

SK Naphtha Propylene 14.6 13.1 0.9 0.3 712.9 712.9 25.09

NL Natural Gas Methanol 13.8 11.6 0.7 0.3 123.6 123.6 25.25

NL Natural Gas Ammonia 15.6 13.5 0.5 0.3 123.6 123.6 25.25

NL Naphtha Ethylene 14.6 13.1 0.9 0.3 597.8 597.8 25.25

NL Naphtha Propylene 14.6 13.1 0.9 0.3 597.8 597.8 25.25

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Appendix B: Process Modelling Process Yield:

�� = �� ⁄

Conversion Rate:

�� = �� ℎ�� ⁄

Methanol Production:

The main reactions to prepare methanol are shown below.

Equation 1 shows the pretreatment of natural gas and desulfurization process to remove H2S by adding

zinc oxide:

ZnO (s) + H2S (g) → ZnS (s) + H2O (g) (Equation 1)

Equations 2 & 3 show the key reactions to prepare syngas using SMR and water gas shift (Kajaste, Hurme,

and Oinas 2018).

CH4 + H2O → CO + 3H2 ∆H0 = +203 kJ/mol (Equation 2)

CO + H2O → CO2 + H2 ∆H0 = -41.2 kJ/mol (Equation 3)

On the other hand, the main reaction to produce syngas using ATR are shown in equations 4, 5, & 6.

CH4 + 1.5 O2 → CO + 2H2O ∆H0 = -520 kJ/mol (Equation 4)

CO + H2O → CO2 + H2 ∆H0 = -41.2 kJ/mol (Equation 5)

CH4 + H2O → CO + 3H2 ∆H0 = +203 kJ/mol (Equation 6)

The reactions in Equations 7 & 8 are the key reactions to produce methanol from syngas and water-gas

shift.

CO +2H2 → CH3OH ∆H0 = -90.6kJ/mol (Equation 7)

CO2 + 3H2 → CH3OH + H2O ∆H0 = -49.5 kJ/mol (Equation 8)

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Ammonia Production:

Equations 9 & 10 shows the methanation reaction.

CO (g) + 3H2 (g) → CH4 (g)+ H2O (g) (Equation 9)

CO2 (g) + 3H2 (g) → CH4 (g) + 2H2O (g) (Equation 10)

The final process to produce ammonia is the Haber Process through the following reaction

N2(g) +3H2 (g) → 2NH3(g) ∆H0 = -92 kJ/mol (Equation 11)

July 2020


Appendix C: Input-Output (I/O) Models This appendix discusses the multi-stage process to build CERI’s Canada Multi-Regional Input-Output (I/O

or I/O) Model (the CMRIO 4.0 model). The section is divided into two parts: the development of the CMRIO

4.0 and the economic sectors covered in the CMRIO 4.0.

I/O models are developed to identify the inter-industry relationships. I/O analysis uses technological

relationships and involves quantities of inputs and outputs in productive processes. The primary reason

for constructing an I/O model is to conduct a multiplier analysis. Multiplier analysis examines the impacts

of shifts in final demand on total output or total factor use. In I/O analysis, "final demand" is defined as

any industry sale that does not serve as a production input to another industry. So, sales to individuals,

investment, and government are included in final demand. In regional models, sales to non-residents

(including non-resident industries) are captured in regional exports, which are part of final demand.

Accordingly, I/O models capture sales among an economy's many industries and other transactions (e.g.,

consumers, government, etc.) and to final demand. The key to building an I/O model is the formation of

a set of fixed coefficient production functions, one for each of the economy's several industries.

CERI CMRIO 4.0

The following illustrates how CMRIO 4.0 was developed, and how one can trace direct, indirect, and

induced effects of the Canadian energy sector on the Canadian economy. The model provides insights at

the provincial and national levels for Canada. The base year for the I/O tables is 2011, as this is the latest

symmetric tables provided by Statistics Canada.

Compilation of the national CMRIO 4.0 includes the following:

1) Statistics Canada provides S level Symmetrical I/O tables (SIOTs) and Final Demand tables for 13

provinces and territories plus Government Abroad. Therefore, there are 14 regional tables for Canada

plus one national table. Provincial data are only available at the S level due to the confidentiality of more

disaggregated data for some sectors in various provinces. The I/O tables used are at producer’s prices

(Basic Prices), meaning that CERI did not construct symmetrical tables from the Use and Make tables, as

the compiled tables were available. As previously mentioned, the base year for the I/O tables is 2011.1

2) SIOTs are balanced. Hence, the use of inputs in the economy is equal to the production of outputs.

3) To highlight the energy sectors in the Canadian provincial SIOTs, CERI disaggregated the “Mining and

Oil and Gas Extraction’’ industry into five sub-sectors: Conventional Oil, Oil Sands, Natural Gas and NGLs,

Coal, and Other Mining. In the same fashion, the manufacturing sector is divided into three sub-sectors:

Refinery, Petrochemical, and Other Manufacturing.

4) It is important to note that the construction sector in this version is already split into the following five

sub-sectors by Statistics Canada: Residential Construction, Non-residential Building Construction,

Engineering Construction, Repair Construction, and Other Activities of the Construction Industry.

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5) CERI combines the SIOTs (13 provincial tables, and one for Government Abroad) to compile one national

I/O matrix. The national matrix is then inverted to generate direct, indirect, and induced effect multipliers.

The following is a brief discussion of the modelling.

July 2020


Appendix D: Supply Forecast and Feedstock Requirement Data The four main products addressed in this report considered at the top of the list of the commonly

consumed chemical intermediate products. Figure D.1 shows the total production versus energy

consumption in 2010. The improvements in the state of art technologies, electricity savings, catalysts,

energy efficiency, and the utilization of BPT changed the market dynamics over the last decade. The

climate change policies will dictate which technologies are the best for use, and this what reforms the

market.

Figure D.1: Energy Consumption versus Production for the Chemical Sector in 2010

Source: (IEA 2013)

The various technologies and feedstock options in the chemical sector make predictions very limited

during the energy transition. For example, Propylene production utilizing propane dehydrogenation (PDH)

technology has fewer carbon emissions compared to the naphtha steam cracking, which led to increased

capacity in North America. However, China, the top olefins consumer, may focus on the methanol to

olefins (MTO) route, which may or may not use natural gas feedstock. The main conclusion is that there

will be more reliance on natural gas consumption over the next three decades to produce the four

products. However, this does not mean that all the global capacities will rely on natural gas, where some

may use renewable or biomass.

Moreover, geopolitics and trading policies will be the main factors during the next three decades. For

example, the European Union has many importers that consume significant amounts of the four

chemicals. However, the exporters are other European Union countries that benefit from the

homogeneous trading system.

July 2020


Products Summary

References: (IEA 2013; ITC 2019; MMSA 2019; Deloitte 2019; DTN 2019; 2020; Stenerson 2019;

Methanex 2015; Methanex Corporation 2019; CER 2020a; Koottungal 2015; Nutrien 2019; IFASTAT

2019)

Methanol Ethylene1 Propylene2 Ammonia

World Demand Quantity in Million Tons/Year

98.3 1643 1114 183

World Imports - 2019 Quantity in Tons Value in Thousand USD Derivatives5 Quantity in Tons Value in Thousand USD

35,318,910 10,355,838

7,868,348 7,684,172

64,859,700 80,014,967

7,964,953 7,542,104

31,123,356 44,705,417

20,154,901 5,815,597

Canadian Imports - 2019 Quantity in Tons Value in Thousand USD Derivatives Quantity in Tons Value in Thousand USD

284,589 90,413

253 146

905,727

1,254,852

696

2,962

544,758 933,110

1,182 1,072

Top five Importers Share of total imports (%)

China (28.1%) Netherlands (8%)

USA (7.4%) India (6.1%) Japan (4.9%)

China (31%) Belgium (24.9%) Germany (8.8%)

Netherlands (7.6%) Indonesia (7.1%)

China (38.6%) Germany (12.4%) Belgium (10.3%)

Netherlands (7.6%) France (4.6%)

India (14%) USA (12.8%)

South Korea (6.8%) Morocco (6.7%)

China (5.6%)

Top five Exporters – Market Share (%) Trinidad and Tobago (15.5%)

Saudi Arabia (12.2%) Iran (10.7%),

US (8.7%) Oman (8%)

Netherlands (15.2%) South Korea (14.1%)

UK (11.5%) Japan (10%)

Singapore (6.3%)

South Korea (21.5%) Netherlands (11.6%)

Japan (10.9%) USA (9.4%)

Taipei, Chinese (7.8%)

Saudi Arabia (28.2%) Russia (15.9%)

Trinidad and Tobago (14.2%)

Indonesia (7.4%) Canada (5.5%)

Canadian Exports - 2019 Quantity in Tons Value in Thousand USD Derivatives Quantity in Tons Value in Thousand USD

387,186 126,868

-

3,568,101 3,849,032

187,006 191,330

91,887

152,515

955,967 382,881

Canadian Exports Market share (%)6 1%

- 2.3% 4.7%

Importers from Canada - 2019 Quantity in Tons Derivatives Quantity in Tons

USA, 384,857 China, 1,965

Cuba, 329

-

USA, 3,105,392 China, 188,999

Mexico, 144,948

USA, 187,006

USA, 65,235 Belgium, 4,236

China, 3,213

USA, 955,882

Netherlands, 43 Australia, 28

Potential Importers Netherlands, India, Japan, South Korea, Switzerland, Spain, Belgium, Turkey,

France

USA, China, Belgium, Germany,

Netherlands, Indonesia, Brazil

China, Mexico, Germany, Belgium,

Netherlands, France, Spain, Italy, Australia,

Brazil

India, Mexico, South Korea, Morocco, Ireland

BAU Scenario for Canada7 (Long-term based on demand) * Units: Million Tonnes/year Current Production Forecasted Production (2050)

0.6

2.348

5.1

12.719

0.4510 1.4411

5.39

7.1912

July 2020


Notes:

1Note: This table compares trading information for different intermediate chemical products. The real value of ethylene shows when trading information addresses derivatives such as polyethylene, although there are other derivatives of ethylene. For example, the value of the world import in 2019 is 24.7 billion USD for the low-density Polyethylene (specific gravity of < 0,94), and 29.8 billion USD for the high-density grades.

2Note: Same as ethylene there is a significant increase in the trading value for polypropylene, where the total value of the world imports in 2019 is 26.2 billion USD. 3 The 2019 world demand amount for ethylene is a compounded value driven from 152 MMT in 2017 using the forecast growth rate of 4 percent. 4 The 2019 world demand amount is compounded based on actual values from 2017 (102 MMT) using growth rate of 4.4 percent. 5 Product: 3901 Polymers of ethylene, in primary forms and Product: 3902 Polymers of propylene or of other olefins, in primary forms 6 The Canadian exports over the total world imports.

7 This scenario considers the five years total imports (2015-2019) and determines the future potential

based on a linear forecast extrapolation. 8 The world demand for methanol has an annual growth of 4.8 percent. 9 The world annual growth rate for ethylene is 3.2 percent. 10 The current propylene production capacity is calculated based on the ethylene steam cracking capacities

in Canada, where propylene is produced as a by-product from feedstock with the following proportions

76 percent ethane, 11 percent propane,9 percent butane,4 percent naphtha. The Capacities for the new

PDH projects currently under construction (1.08 million Tons per year) are not addressed. 11 The annual growth rate for propylene production capacities is 4.1 percent. 12 The world plant capacities for ammonia between 2014-2019 have an annual growth of 1 percent.

July 2020


Methanol Scenario 1

Year MMT/yr Growth Billion cubic feet of natural gas

Billion Cubic Meter of Natural Gas

2020 0.60 0.03 24.14 0.68

2030 0.96 0.36 38.58 1.09

2040 1.53 0.57 61.65 1.75

2050 2.34 0.80 94.02 2.66

Scenario 2



2020 1.24 0.06 49.80 1.41

2030 1.98 0.74 79.59 2.25

2040 3.16 1.18 127.19 3.60

2050 4.82 1.66 193.96 5.49

Scenario 3



2020 1.94 0.09 78.22 2.21

2030 3.11 1.16 125.01 3.54

2040 4.97 1.86 199.78 5.66

2050 7.57 2.61 304.65 8.62

July 2020


Ammonia Scenario 1



2020 5.39 0.05 158.66 4.49

2030 5.95 0.56 175.26 4.96

2040 6.58 0.62 193.60 5.48

2050 7.19 0.62 211.73 5.99

Scenario 2



2020 5.59 0.06 164.63 4.66

2030 6.18 0.59 181.85 5.15

2040 6.82 0.65 200.88 5.69

2050 7.46 0.64 219.70 6.22

Scenario 3



2020 6.00 0.06 176.49 5.00

2030 6.62 0.63 194.96 5.52

2040 7.32 0.69 215.36 6.10

2050 8.00 0.69 235.53 6.67

July 2020


Ethylene Scenario 1

Year MMT/yr Growth WCS MMBBL/yr SCO MMbbl/yr

2020 5.10 0.16 1156.00 550.48

2030 6.99 1.89 1584.00 754.29

2040 9.58 2.59 2170.46 1033.55

2050 12.71 3.14 2881.83 1372.30

Scenario 2


2020 6.73 0.22 1526.21 726.76

2030 9.23 2.49 2091.27 995.84

2040 12.64 3.42 2865.54 1364.54

2050 16.79 4.14 3804.73 1811.78

Scenario 3


2020 6.73 0.22 1526.21 726.76

2030 9.23 2.49 2091.27 995.84

2040 12.64 3.42 2865.54 1364.54

2050 16.79 4.14 3804.73 1811.78

July 2020


Propylene Scenario 1


2020 0.45 0.02 235.38 112.09

2030 0.67 0.22 351.79 167.52

2040 1.01 0.33 525.77 250.36

2050 1.44 0.44 754.83 359.44

Scenario 2


2020 1.39 0.06 725.16 345.31

2030 2.07 0.69 1083.78 516.09

2040 3.10 1.02 1619.75 771.31

2050 4.45 1.35 2325.44 1107.35

Scenario 3


2020 2.17 0.09 1134.08 540.04

2030 3.24 1.07 1694.93 807.11

2040 4.84 1.60 2533.15 1206.26

2050 6.95 2.11 3636.78 1731.80

July 2020


July 2020


Appendix E: Further Detailed Results

Direct and Indirect Impact on National GDP (US$ Million)

Reference Business Case (RBC)

Product Construction Operation

AB SK NL AB SK NL

Ammonia 41.00 38.27 20.5 20.5

Ethylene 47.23 44.08 16.66 15.55

Methanol 32.80 30.6 7.85 7.85

Propylene 22.63 21.12 7.99 7.45

Competitive Business Case (CBC)

Product Construction Operation

AB SK NL AB SK NL

Ammonia 77.9 72.71 41.00 41.00

Ethylene 88.56 82.66 27.62 27.62

Methanol 83.64 78.06 16.07 16.07

Propylene 42.44 39.61 13.24 13.24

Direct and Indirect Impact on Provincial GDP (US$ Million)

Product Reference Business Case (RBC)


AB SK NL AB SK NL

Ammonia 35.80 33.41 17.90 17.90

Ethylene 41.24 38.49 14.55 13.59

Methanol 28.64 26.73 6.85 6.85

Propylene 19.76 18.44 6.97 6.5

Product Competitive Business Case (CBC)


AB SK NL AB SK NL

Ammonia 68.02 63.49 35.80 35.80

Ethylene 77.33 72.17 24.11 24.11

Methanol 73.05 68.16 14.03 14.03

Propylene 37.05 34.58 11.55 11.55

July 2020


0

10

20

30

40

50

60

70

80

AB SK NL AB SK NL


$ M

illio

n

RBC-GDP Impact (Provincial)


0

10

20

30

40

50

60

70

80

AB SK NL AB SK NL


$ M

illio

n/y

ear

CBC-GDP Impact (Provincial)


July 2020


Product Direct and Indirect Impact on Tax Revenue-Canada (US$ Million)


AB SK NL AB SK NL

Ammonia 3.27 3.33 3.87 6.07 6.16 7.43

Ethylene 15.00 15.11 12.98 26.08 26.17 22.34

Methanol 3.75 3.86 4.73 8.1 8.29 10.61

Propylene 7.19 7.25 6.22 12.5 12.5 8.26

Product

Direct and Indirect Impact on Tax Revenue-Provincial (US$ Million)


AB SK NL AB SK NL

Ammonia 2.58 2.63 3.05 4.8 4.87 5.88

Ethylene 11.89 11.97 10.28 20.68 20.75 17.71

Methanol 2.96 3.05 3.74 6.25 6.54 8.4

Propylene 5.69 5.74 4.92 9.91 9.94 8.48

0

5

10

15

20

25

30

AB SK NL AB SK NL


$ M

illio

n/y

ear

Direct and Indirect Impact on Tax Revenue-Provincial


July 2020


Product

Direct & Indirect Jobs Supported-Canada


Construction Period Operation Period

AB/SK NL AB/SK NL

Ammonia 27,092 25,286 1,506 1,506

Ethylene 31,209 29,129 1,224 1,142

Methanol 21,674 20,229 577 577

Propylene 14,954 13,958 587 548

Product



AB/SK NL AB/SK/NL

Ammonia 51,474 48,042 3,011

Ethylene 58,518 54,617 2,028

Methanol 55,267 51,581 1,180

Propylene 28,040 26,171 972

Product

Direct & Indirect Jobs Supported-Provincial



AB/SK NL AB/SK NL

Ammonia 20,161 18,817 1,121 1,121

Ethylene 23,225 21,677 911 850

Methanol 16,129 15,053 429 429

Propylene 11,129 10,387 437 408

Product



AB/SK NL AB/SK/NL

Ammonia 38,305 35,751 2,241

Ethylene 43,547 40,644 1,509

Methanol 41,127 38,386 879

Propylene 20,866 19,475 723

July 2020


0

10,000

20,000

30,000

40,000

50,000

60,000

AB SK NL AB SK NL

RBC CBC

Per

son

-yea

rDirect & Indirect Jobs-Canada (Construction Period)


0

10,000

20,000

30,000

40,000

50,000

60,000

AB SK NL AB SK NL

RBC CBC

Per

son

-yea

r

Direct & Indirect Jobs-Provincial (Construction Period)


July 2020


0

500

1,000

1,500

2,000

2,500

3,000

AB SK NL AB SK NL

RBC CBC

Per

son

-yea

rDirect & Indirect Jobs-Provincial (Operation Period)


July 2020


Appendix F: Regional Price Data in 2019 Average 2019 Prices1

References: (MMSA 2020b; Methanex 2020; Sims 2019; Everchem Specialty Chemicals 2019; Hay 2019;

DTN 2020; 2019; Ewing 2019; Weddle 2019; Petrotahlil 2019; Fibre2Fashion 2020a; ICIS 2019;

Fibre2Fashion 2020b)

Region Methanol Ethylene Propylene Ammonia North America Spot Price (Min-Max) Contract Price (Min-Max)

234 - 361 (FOB) 1 340 - 442 (FOB)

276 - 617 (FOB) 524 - 656 (FOB)

728-1323 (FOB) 805-1345 (FOB)

350 (FOB) 220-280(CFR)1

Europe

Spot Price (Min-Max) Contract Price (Min-Max)

227-319 (FOB) 307-410 (FOB)

860-1220 (FD)1 1090-1210 (FD) (

850-1115 (FD) 940- 1110 (FD)

-

200-2751

Asia Spot Price (Min-Max) Contract Price (Min-Max)

231-3051 233-370

750- 1176 (CFR) 950-955 (FOB)

860 - 960 (CFR) ( 857 – 870 (FOB)

-

240-3401 (FOB)

Middle East Spot Price (Min-Max) Contract Price (Min-Max)

- -

- -

- -

V2190-275 (FOB)

Notes_______________________

1 Units are in USD/Metric Ton 1 free on board (FOB) the buyer pays for transportation (MMSA 2020b; Methanex 2020).

1 Cost and freight (CFR) requires the seller to arrange for the transport to the buyer's destination. 1 free delivered (FD) northwest European basis (NWE) 1 European price is based on Yuzhny contract price. 1 Average contract price in NEA/SEA and Methanex Asian Posted Contract Price in 2019. 1 Average contract prices in 2019 represent different Asian countries including India, South Korea, and Taiwan.

July 2020


Appendix G: Existing and Emerging Technologies The following section aims to present the existing plants in Canada, summarize the manufacturing

process, highlight the major technology vendors for each product.

The products addressed in this study are chemicals or intermediates used to create a wide range of final

products. The following section aims to present the existing plants in Canada, summarize the

manufacturing process, highlight the major technology vendors for each product.

Methanol

The methanol production process starts by treating raw natural gas, where the main portion goes to the

methanol plant as a feedstock, and a smaller portion is used as a fuel to prepare steam and other facility

requirements. The reforming section converts methane, steam, and other compounds to syngas (H2 + CO

+ CO2).

There are different technologies for steam reforming, such as steam methane reforming (SMR),

autothermal reforming (ATR), and partial oxidation (POX). Most methanol plants use SMR for the

reforming stage, mainly due to its higher H2/CO ratio. Few large scale plants use the ATR process, which

produces lower GHG emissions. However, literature indicated that when both technologies are combined

(SMR and ATR), it improves the conversion efficiency, lowers fuel consumption, thereby translating into

lower GHG emissions from the process (Natgasoline, LLC 2013).

The NG route process could be summarized into three main steps: 1) Reforming; 2) Methanol synthesis;

and 3) Distillation. Figure G.1 shows a block diagram for the commonly used process in the NG route.

Figure G.1: Methanol Production Process from Natural Gas

July 2020


Technologies

The leading technology vendors for methanol plants frequently cited are Air Liquide (Lurgi), Johnson

Matthey (DAVY), Haldor Topsøe, Primus STG+™.

Air Liquide (Lurgi)

Lurgi methanol technology is a subsidiary of Air Liquide that provides methanol technologies with

commercial products such as Low-Pressure methanol (medium scale, less than 1 million tonnes per year)

and Mega Methanol™ (large scale, more than 1 million tonnes per year) plants. These plants use mainly

natural gas and coal feedstocks. The Low-Pressure methanol is produced by converting syngas to raw

methanol over a copper catalyst in a water-cooled reactor.

However, the Mega Methanol™ uses a two-stage (water-cooled, followed by gas-cooled) reactor to

convert synthesis gas to methanol. In both processes, unconverted syngas is recycled back to the synthesis

step to enhance yield and carbon efficiency. This technology has integrated syngas generation from

natural gas. The natural gas passes over a copper catalyst in a two-step synthesis process involving water-

cooled and then gas-cooled reactors. These two-stage reaction process allows low recycle ratios leading

to reduced equipment sizes and therefore large single train capacities. The unconverted syngas is recycled

to the synthesis loop to increase yield and improve carbon efficiency. The commonly used plant has a

capacity of 5,000 tonnes per day (tpd). The natural gas consumption is 29 MMBTU/tonne (Air Liquide

2020).

Johnson Matthey's DAVY™

The synthesis technologies convert syngas (CO, CO2 & H2) to methanol via exothermic reactions that have

a limited conversion rate, then go through a reactor to produce sufficient methanol. The syngas feed

composition determines the exact design of the methanol loop. Converter designs vary based on how

reaction heat is removed.

Haldor Topsoe

SynCOR Methanol™ is a Proven large-scale technology for greenfield facilities. Optimal single train

capacity is 500 tpd up to 10,000 tpd. This technology relies on ATR rather than conventional SMR. The

syngas generator based on oxygen reforming at unique low steam carbon is the core of the process.

However, Haldor Topsoe also has a proprietary methanol process technology for smaller capacity plants

of 215 metric tonnes per day, which can be used for flare gas and associated natural gas (Haldor Topsoe

2020).

Primus STG+™

The technology converts stranded methane, ethane, propane and butane (C1 to C4 natural gas liquids) to

methanol using their Gas-to-Methanol STG+™ System or to gasoline using their Gas-to-Gasoline STG+™

System. Primus STG+™ technology’s modular design presents prospects for utilization and monetization

of gas resources in remote locations with minimal natural gas pipeline infrastructure (Primus Green

Energy 2020).

July 2020


Ammonia

The initial processes in ammonia production are similar to methanol production. Raw natural gas is

pretreated from sulphur, then converted by primary and secondary reforming to produce syngas, then

through water-gas shift to extract H2 from CO, then the removal of CO2, then methanation to remove the

syngas residuals such as CO & CO2 and turn it to methane. The final stage is the ammonia synthesis. Figure

G.2 shows the main stages for ammonia manufacturing from natural gas.

Figure G.2: Ammonia Production Process from Natural Gas

Technologies

The vendors for ammonia production are but not limited to Haldor Topsoe, Johnson Matthey, Kellogg

Brown and Roots (KBR).

Haldor Topsoe

Haldor Topsoe is a technology supplier to the ammonia industry. Natural gas is hydrogenated over a

hydrogenation catalyst to convert organic sulphur compounds into hydrogen sulphide (H2S). H2S is

absorbed in a zinc oxide catalyst in the sulphur absorber. The product then goes through a two-stage

reforming process followed by a water gas shift reaction in two adiabatic stages and then a non-catalytic

CO2 removal.

Thyssenkrupp Industrial Solutions

Thyssenkrupp (formerly known as Uhde) provides EPC services and technology to the ammonia industry.

Natural gas is first desulphurised and then goes through a two-stage reforming process. Process heat is

recovered for steam generation. Then the gas is directed to a water gas shift reaction in two adiabatic

stages to convert CO and water to hydrogen and then through a CO2 removal process by absorption of

CO2 into an absorption liquid. Residual amounts of unwanted CO and CO2 are converted to methane in

the methanation unit, producing a synthesis gas which mainly consists of hydrogen and nitrogen. This gas

is compressed to synthesis pressure and is fed to a single or multi reactor system with heat recovery for

July 2020


steam generation in order to convert it to ammonia. Liquid ammonia is removed from the process by

cooling and condensation.

Johnson Matthey

Johnson Matthey is very focused on the R&D and development of ammonia catalysts such as KATALCOTM.

The process uses both primary and secondary reformers. Excess air is used in the secondary reformer and

generated heat is transferred to the primary reformer through direct heat exchange in a tubular gas-

heated reformer. In this process, a single-stage carbon monoxide shift reaction using a copper base

catalyst is employed. Synthesis gas produced is purified by removing CO2, and excess nitrogen. The final

stage involves low-pressure ammonia synthesis using a cobalt promoted catalyst. The carbon dioxide by-

product of the process is separated using amine solvents, which is a process similar to that used in carbon

capture for coal-fired electricity generation (Johnson Matthey 2018).

KBR

KBR has an advanced Ammonia Process KAAPplus that combines three major features of the KBR’s

ammonia technology. These are 1) the Reforming Exchange System, 2) the Cryogenic Syngas Purifier, and

3) the Advanced Ammonia Process. The process precludes a primary reformer and uses heat exchanger-

based synthesis reactors for steam methane reforming and ammonia production. The KAAPplus combines

autothermal reforming and a reforming exchanger arranged in parallel to achieve high conversion of

synthesis gas. The synthesis gas is sent to high and low-temperature carbon monoxide shift converters.

Also, a low-pressure and highly active catalytic process for ammonia synthesis is used.

Ethylene

Steam cracking it the most common method to produce ethylene. As stated before, this study focuses on

using naphtha as a feedstock.

The steam cracking of naphtha requires more energy that produces more emissions compared to ethane

cracking due to the lower ethylene yield, which is typically around 80 percent and 30 percent for ethane

and naphtha cracking, respectively (Tao Ren, Patel, and Blok 2006). However, the best Practice

technologies (BPT) can significantly reduce the energy consumption and related emissions for steam

cracking in general (Li et al. 2010; IEA 2019). The economies of scale is also an important factor to reduce

the total energy of the facility. For instance, the world scale naphtha crackers that produce 1 million

tonnes per year of ethylene can see reduced energy requirements by around 12 percent compared to

crackers that produce half the amounts (Li et al. 2010).

Figure G.3 below shows the process block diagram for ethylene production (and propylene) using the

naphtha route.

July 2020


Figure G.3: Ethylene and Propylene Production Process from Naphtha

As shown in Figure G.3, the naphtha goes into the steam cracking furnace, mainly the convection section

of a pyrolysis furnace, through multiple heat exchangers for preheating to 650 °C. Then, naphtha mixes

with superheated steam and passes through tubes, made of chromium-nickel alloys. The pyrolysis takes

place mainly in the radiant section of the furnace, where tubes are externally heated to 750–900 °C. The

pyrolysis section of a naphtha steam cracker consumes around 65 percent of the total process energy and

approximately 75 percent of the total exergy loss. Once the cracked gas leaves the furnace, it is quenched

in the transfer line exchangers (TLE) to 550–650 °C, followed by a series of heat exchangers to drop the

temperature to 300 °C.

The next step is the compression stage, where it goes through four or five stages of gas compression with

temperatures at approximately 15–100 0C, then cooling and finally cleanup to remove acid gases, carbon

dioxide and water. The final step is the recovery of ethylene and propylene through fractionation or

distillation, refrigeration and extraction processes. The equipment in this stage includes chilling trains and

fractionation towers, refrigeration, de-methanizer, de-ethanizer and de-propanizer, and de-butanizer

(Tao Ren, Patel, and Blok 2006).

Cracking reaction and quenching, product compression and drying, and separation of products and co-

products. the yield of ethylene from cracking naphtha is 30 percent with the other co-products such as H2

and CH4 (17 percent), propylene (3 percent), butadiene (2 percent), C4 olefins (1 percent), pyrolysis

gasoline (2 percent) and benzene (1 percent) (Ghanta, Fahey, and Subramaniam 2013).

The total energy at lower heating value (LHV) for naphtha cracking varies between facilities around the

world, size, technologies. However, using state-of-the-art technologies can bring the total energy to 16-

20 GJ/t ethylene, including the electricity requirement, which is around 1 GJ/t ethylene (Li et al. 2010; T.

Ren 2009; IEA 2019).

July 2020


Technologies

The main licensors for ethylene and propylene production from naphtha are TechnipFMC plc, McDermott,

Linde, and KBR.

TechnipFMC technology

The average capacity of production of ethylene steam crackers, are around 1,500 KTA. For liquid cracking,

GK6® and USC® U-coils are designed for short-residence time. There is a unique linear quench exchanger

arrangement that eliminates the need for offline cleaning and reduces waste. This arrangement can be

applied to all coil types. The Transfer Line Exchanger (TLE) recovers heat from furnace outlets without

fouling to produce very high-pressure steam. The average ethylene yield is 35 percent (wt percent)

(TechnipFMC plc 2017). In addition to the typical yield of ethylene and propylene from olefinic units such

as steam cracker, Deep Catalytic Cracking (DCC) or Fluid Catalytic Cracking (FCC) units, also the process

known as the OMEGA technology, which can be integrated to increase the propylene yield without

consuming ethylene product. The production of propylene from C4/C5 feed streams in the OMEGA

process increases the overall propylene to ethylene ratio and has a lower specific energy consumption

than steam cracking alone (TechnipFMC plc 2018).

McDermott (Lummus Technology)

The Lummus Technology's ethylene process is known for the patented SRT® (Short Residence Time)

pyrolysis heater, which can process feedstocks ranging from ethane to vacuum gasoil. the transfer line

exchangers “Bath Tub” and “Quick Quencher.” Both provide quick quench to the cracking effluent for high

ethylene yield and extended TLE run length. The Olefins Conversion Technology (OCT) uses metathesis

and isomerization chemistry to produce propylene from reacting ethylene with C4 and/or C5 olefins from

steam cracking, refinery processes, MTO or ethylene dimerization. Polymer grade propylene is produced

in a simple catalytic fixed bed reactor without the use of super fractionators. The metathesis reactions are

mildly exothermic, and no energy input into the reaction, making OCT the only route to propylene that

does not require energy input to the reaction step (McDermott 2020).

Linde

Modern steam crackers can produce up to 1.5 million tons of ethylene per year and 600,000 tons of

propylene per year. The PyroCrack® technology allows the use of different feedstocks (from ethane to gas

oil). The technology has short-residence time coil design to maximize olefin production. In cracking

furnaces, cracked gases are produced after quenching and delivered to the separation train where the

cracked gas can be separated into individual products. Selas twin radiant cell design, two radiant cell

cracking furnaces with a common intermediate convection section. The furnaces are equipped with state-

of-the-art low NOx or ultra-low NOx burners, or Linde can be designed with a selective catalytic reduction

(SCR) system incorporated in the convection section (Linde 2020).

July 2020


KBR

In KBR the main technology for steam cracking is Selective Cracking Optimum Recovery (SCORE™), where

it uses various feedstocks including naphtha. The K-COTTM technology gives an alternative for higher

propylene-to-ethylene ratio; a typical P/E is 2 (olefinic) or 1 (paraffinic). Also, the MAXOFIN™ is an FCC

process that enables refiners to maximize propylene production by 20 percent (KBR 2020).

Propylene

Propylene is one of the main components in the HVC after ethylene. The cracking process yield between

13-23 percent propylene (Tao Ren, Patel, and Blok 2006). The propylene yield from steam cracking is

considered very low compared to the propane dehydrogenation (PDH) technology that is commonly used

in North America. However, adding catalysts and using the metathesis process can significantly increase

the propylene yield from naphtha cracking.

As stated earlier, energy requirements and emissions for propylene production can be close to ethylene

(DECHEMA/IEA/ICCA 2013). Despite the difference in the yield for the two products. Using a catalyst, or

the metathesis process that converts ethylene and butane-2 to propylene increases the propylene yield

to get roughly close to the ethylene (Tao Ren, Patel, and Blok 2006). It is important to note that the

metathesis can produce a one-third of the propylene product catalytically rather than thermally, which

reduces the energy consumption of about 15 percent, eventually adds a small amount of energy (around

1 Gj/t for a state-of-art propylene conversion unit) to the overall cracking facility(Gulf Publishing Company

2010).

The steam cracking process and technology vendors for propylene production from naphtha are similar

to the ones highlighted in the ethylene production section.

Asphalt

The term asphalt is used in North America for the heavy distillation bottoms/residuum that are highly

viscous, used as binding material for road paving. The same material is known as bitumen in Europe, and

it is different from the bitumen produced from oil sands in Canada.

In a large-scale refinery where multiple products processed, the desalting process takes place first, when

the salt content is higher than 10lb/1000 bbl of oil. Desalting is important to reduce corrosion and

minimize the fouling of process units and heat exchangers. Generally, heavy crudes contain more salt. In

the desalting process, the crude is washed with 3-10 percent water at 90-190°C, so that the salt dissolves

in water, then water is separated from crude oil using an electric current (Energy Star 2015). The efficiency

of this process is dependent on pH, specific gravity, and salt content.

After desalting, the crude goes through a distillation process that separates different products based on

the differences in boiling temperature or vapour pressure. These properties are related to the molecular

weight or molecular size range of the distilled petroleum fraction.

The first stage in the distillation process is the atmospheric fractionation, where the crude oil goes to a

crude distillation unit (CDU), which is a distillation tower. The crude is heated in a furnace to 370–390°C,

July 2020


typically the heating process happens over two stages. It is important to note that the temperature is

relatively low, otherwise, the oil products will begin to crack or decompose. The tower separates each

product into its designated tray based on its boiling point. The products are separated into three

categories: 1) light fraction such as fuel gas, LPG and gasoline; 2) middle fraction kerosene, naphtha, and

diesel oil; and 3) heavy fractions such as fuel oil, that cannot be distilled off without enough heat.

The heavy components have the lowest economic value that require further processing. The heavy

components, including asphalt, remain at the bottom of the distillation column, also known as residuum.

Those residuum or bottoms contain high boiling, heavy petroleum fractions, such as gas oils, lube oil

stocks, and asphalts.

The next stage is the vacuum tower, which is also known as the vacuum distillation unit (VDU). The process

separates these heavy products by reducing the pressure (which decreases the boiling points) and

facilitates the separation process. This process is heated at 390-450ºC, which does not cause undesirable

thermal cracking reactions. The amount and type of asphaltic materials in different crude oils varies,

which means that different refineries using crude oils from different sources may adjust the operating

conditions to produce asphalt with the desired properties.

A further process such as Deasphalting (solvent Deasphalting) can increase the extraction of higher value

products from the VDU bottoms and separate it from the asphalt, as shown in Figure G.4.

In the Solvent Deasphalting (SDA) process, the residuum is pumped and mixed with a liquefied solvent

such as propane or propane-butane mixture. The solvent to feedstock volumetric ratios can be around 4

to 6. The temperature is relatively close to the critical temperature for the solvent so that the dissolved

naphthenic and aromatic oils separate from the solution.

It is important to note that the energy requirements for asphalt production are insignificant compared to

other processes in a refinery (Harrigan and Leahy 1990).

July 2020


Figure G.4: Asphalt Production from Crude Oil

Carbon Fiber (CF)

Carbon fibre (CF) is a material consisting of fibres that are 92 percent or higher carbon and environment

friendly. Carbon fibre is made from long strands of carbon blended with plastic resin. It is stronger than

steel, up to 10 times as strong, and much lighter. Moreover, it doesn’t corrode. It is a great alternative

and can be used in vehicles, bicycles, golf clubs or even wind turbine blades. However, due to its steep

price, it is used primarily in racing cars and next-generation prototypes.

The first carbon fibre from polyacrylonitrile (PAN) was produced by Du Pont in 1946 in the US. This

method, including the subsequent ones for the production of carbon fibres from PAN, was destined to be

used for fabrics. Although carbon fibres can be produced from rayon and lignin, traditionally, it has been

produced form PAN. The SGL Automotive Carbon Fibres LLC at Moses Lake, Washington is considered an

example to explain the process below (Stantec 2018):

Production of the precursor:

Step (1-2) Crude oil extraction.

Step (3) Refining of crude oil to produce ammonia and propylene.

Step (4) Production of acrylonitrile monomer in Japan.

Step (5) Polymerisation acrylonitrile (and comonomers) to PAN polymer in Japan.

Manufacture of Fiber (uncarbonized and carbonized):

July 2020


Step (6) Spinning of PAN to a white fibre and winding to spool in Mitsubishi Rayon, Japan.

Step (7) Oxidation and Carbonisation of the white PAN fibre to black CF at SGL Moses Lake,

US. 3. The weaving of carbonized fibre.

Weaving of CF:

Step (8) spools into textile layers at Wackersdorf, Germany.

Step (9) Lay-up, mat cutting and forming of carbon fibres at BMW, Landshut and Leipzig.

Lay-up for the final product:

Step (10) Incorporation to Carbon Fibres components into the final form (component and in

turn part of the vehicle assemblage) at BMW, Landshut and Leipzig.

Due to the high economic and energy cost of producing CF from PAN, CF producers are vigorously

exploring the alternative of PAN. The carbon utilization perspective is important while considering the

feedstock other than PAN. Pitch, which is another CF precurse that can have a carbon yield of up to 90

percent (Stantec 2018). Although straight unmodified pitch has a low chance of meeting the necessary

specifications for a spinnable pitch, therefore it would require separation, purification and modification

before it can be used as a feedstock for carbon fibres production. The physical and chemical properties of

CF from different feedstocks are different due to the purity level. The CF derived from bitumen would be

catering to a new market of construction industry, not only to the automotive industry. Also, geographical

origin and processing history need to be considered while deciding feedstock.

The current process of the manufacturing process of carbon fibre from crude oil is highly energy-intensive.

It is made from crude oil to obtain acrylonitrile and then baking it to convert into yarn. The carbonization

and polymerization phase of acrylonitrile into carbon fibres is done at 1000 0C or more. Therefore, more

than 20 tonnes of carbon dioxide is released in the production of just 1 tonne of CF.

On the other hand, manufacturing carbon fibres from bitumen would reduce this energy requirement as

the feedstock for the production of these fibres would be asphaltenes, which is >85 percent carbon-rich.

The technology is still under development for producing CF from bitumen. There are no studies done yet

on the economic and environmental impacts of pitch derived carbon fibres. Affordability plays a critical

role in adopting any emerging technology, resulting in the adaptation of CF to medium and lower

technologies and products.

Documents

ECONOMIC IMPACTS OF VALUE-ADDED OIL AND GAS PRODUCTS