Study No. 139
May 2014
CANADIAN
ENERGY
RESEARCH
INSTITUTE
NATURAL GAS LIQUIDS (NGLS) IN
NORTH AMERICA: AN UPDATE
PART II – MIDSTREAM AND
DOWNSTREAM INFRASTRUCTURE
Canadian Energy Research Institute | Relevant • Independent • Objective
NATURAL GAS LIQUIDS (NGLs) IN NORTH AMERICA: AN UPDATE
PART II – MIDSTREAM AND DOWNSTREAM INFRASTRUCTURE
Natural Gas Liquids (NGLs) in North America: An Update
Part II – Midstream and Downstream Infrastructure
Copyright © Canadian Energy Research Institute, 2014
Sections of this study may be reproduced in magazines and newspapers with acknowledgement
to the Canadian Energy Research Institute
ISBN 1-927037-20-1
Author:
Carlos A. Murillo
Acknowledgements:
The author wishes to acknowledge the support and contributions of Peter Howard and Megan
Murphy in the production, reviewing, and editing of this report.
Julie Dalzell and Anthony Mersich provided most of the research and material on the United
States’ sections. Staff from RBAC Inc. (Sherman Oaks, California) and RBN Energy LLC (Houston,
Texas) provided feedback and data for cross-referencing and due diligence purposes on the
United States.
Additionally, industry peer-reviewers from across the integrated oil and gas, midstream, and
consulting segments provided valuable feedback and suggestions that helped make these
reports more relevant, independent, and objective in accordance with CERI’s mandate.
CANADIAN ENERGY RESEARCH INSTITUTE
150, 3512 – 33 Street NW
Calgary, Alberta T2L 2A6
Canada
www.ceri.ca
May 2014
Printed in Canada
Front cover photo’s courtesy of
http://www.huskyenergy.com/news/photolibrary/westerncanadaconventional.asp; Pembina Pipeline Corporation,
Corporate Update January 2014; and http://www.lyondellbasell.com/News/PhotosforMediaUse/
Natural Gas Liquids (NGLs) in North America: An Update
Part II – Midstream and Downstream Infrastructure
iii
Table of Contents
LIST OF FIGURES .............................................................................................................
LIST OF TABLES ...............................................................................................................
EXECUTIVE SUMMARY ....................................................................................................
NGL INFRASTRUCTURE AND NGL END-USERS IN CANADA ...............................................
Natural Gas Field Processing Plants and Straddle Plants ..................................................
Fractionators ......................................................................................................................
Pipelines and Other Transportation Infrastructure ...........................................................
Natural Gas Transmission and Distribution Systems ...................................................
Liquids Transportation System ....................................................................................
Rail Transportation Infrastructure ...............................................................................
Refineries, Upgraders, and Off-gas Processing Plants .......................................................
Petrochemical Facilities: Steam Crackers, Aromatic Plants, Derivative Plants,
and Others ...................................................................................................................
NGL INFRASTRUCTURE AND NGL END-USERS IN THE UNITED STATES ..............................
Natural Gas Processing Plants ...........................................................................................
Fractionators ......................................................................................................................
Pipelines and Other Transportation Infrastructure ...........................................................
Liquids Transport Infrastructure ..................................................................................
Petrochemical Facilities .....................................................................................................
ANALYSIS: INFRASTRUCTURE INVESTMENTS IN CANADA TO CONNECT
NGL SUPPLY AND DEMAND .......................................................................................
Major Midstream Players in Western Canada ...................................................................
Trends in Midstream Infrastructure Investments .............................................................
Downstream Investments Associated with Increasing NGL Supplies in Canada ...............
APPENDIX I – CANADIAN NGL INFRASTRUCTURE ............................................................
APPENDIX II – UNITED STATES NGL INFRASTRUCTURE .....................................................
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Natural Gas Liquids (NGLs) in North America: An Update
Part II – Midstream and Downstream Infrastructure
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List of Figures
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
1.10
1.11
1.12
1.13
1.14
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
3.1
3.2
3.3
3.4
Illustrative Canadian NGL Supply and Demand Flowchart ..........................................
Gas Processing and NGL Extraction Process ................................................................
Gas Gathering, Processing, and Transmission System in NE BC, Gas
Distribution System, and NGL Gathering System ........................................................
Western Canada Natural Gas Processing and Transportation System ........................
Map of Deep-cut Field Gas Processing Plants in the WCSB.........................................
Canadian Natural Gas Transportation Infrastructure and Distribution
Companies/Areas .........................................................................................................
Canadian Crude Oil Pipeline System ............................................................................
Canadian NGL Pipeline Infrastructure Capacities, and Main NGL Storage
Facilities and Capacities ...............................................................................................
NGLs Transported to Fort Saskatchewan and Pipeline Capacity and
Peace LVP System Throughput Estimates and Capacity ..............................................
North America’s Rail Transportation Network ............................................................
Petrochemical Feedstock and End-use Flowchart .......................................................
Moving Up the Value Chain from Hydrocarbons to End-use Products .......................
Canadian Petrochemical Production and 2012 % Share of Total ................................
Total Petrochemical Production in Canada by Source, and Estimated
Ethylene Production from Steam Crackers by Feedstock ...........................................
Gas Processing Capacity in the United States Lower 48 ..............................................
US Lower 48 Gas Processing Capacity Additions by Region, 2011-2016 .....................
US Lower 48 Gas Processing Capacity by Region, 2004-2016 .....................................
Marcellus/Utica Gas Processing Capacity, 2004-2016 ................................................
US Fractionation Capacity by Region and by Operator, 2012 .....................................
Fractionation Capacity Additions by Area and Operator, 2011-2016 .........................
US Fractionation Capacity by Region ...........................................................................
Marcellus/Utica Total Fractionation and De-ethanization Capacity ...........................
Major NGL Pipeline Corridors and Fractionation Centers in the United States ..........
Top Natural Gas/NGL Players in AB: Natural Gas Production and Field
Processing, NGLs Extraction.........................................................................................
Top Natural Gas Processing/NGL Extraction Players in BC ..........................................
Oil and Gas Investment Risk and Return Continuum ..................................................
NGL Pipeline Capacity and Fractionation Capacity in the Fort Saskatchewan
Area, 2002-2018...........................................................................................................
4
5
6
7
10
13
16
17
18
22
25
25
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Natural Gas Liquids (NGLs) in North America: An Update
Part II – Midstream and Downstream Infrastructure
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List of Tables
1.1
1.2
1.3
1.4
1.5
1.6
1.7
2.1
2.2
2.3
2.4
3.1
3.2
3.3
Information on Deep-cut Field Gas Processing Plants in the WCSB ............................
WCSB Straddle Plant Information, AB Straddle Plants Processing Volumes
and Utilization ..............................................................................................................
Total Canadian Fractionation Capacity and Fort Saskatchewan Fractionators
NGL Production and Capacity Utilization/Stand-alone Fractionation Capacity
Information ..................................................................................................................
Large Canadian Midstream Companies NGL Rail Handling Facilities and
Rail Car Fleet ................................................................................................................
Canadian Refining and Upgrading Capacity and Off-gas Processing Plants ................
Canadian Petrochemical Plant Information .................................................................
Major Petrochemical Clusters in Canada, Summary ...................................................
Natural Gas Processing Plants, Number and Capacity by PADD and Top 50
Owners’ Capacity in the US Lower 48 ..........................................................................
US NGL Pipelines ..........................................................................................................
US Ethylene Cracking Capacity by Region/Company and Estimated
Feedstock Requirements .............................................................................................
US Petrochemical Facility Expansions and New Constructions ...................................
Recent Gas Processing/NGL Infrastructure Investments in Western Canada .............
Alberta’s Incremental Ethane Extraction Program: Projects Information, 2012........
Recent and Announced NGL Downstream Investments in Canada ............................
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Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
1
Executive Summary
Following Part I of the NGL update (upstream), this report (Part II) presents an overview of the
infrastructure required to move NGLs from production sources to markets and end-users, while
identifying some of those end-users, primarily, petrochemical facilities, both in Canada and the
United States (US). This report also presents some of the trends observed around midstream
and downstream infrastructure investments in Canada targeting the monetization of NGLs.
The infrastructure required to extract and market natural gas and natural gas liquids in North
America is complex and extensive. This infrastructure includes gas processing plants and
pipelines (gathering, transmission, and distribution systems), refineries, NGL fractionators, NGL
mix and delivery pipelines, rail cars, NGL storage facilities, as well as petrochemical facilities.
Canada and the United States combined account for over 1,200 field gas processing plants with
close to 100 billion cubic feet per day (Bcf/d) of gas processing capacity, with the majority of
these plants located in major gas producing regions including the US Gulf Coast (PADD III), the
Western Canadian Sedimentary Basin (WCSB), and the US Rockies (PADD IV). Meanwhile, as gas
production has accelerated in certain areas of North America, gas processing infrastructure is
expanding not only in traditional areas but also in those areas where new infrastructure is
needed including the US Midwest (PADD II), but more importantly, the US North East (PADD I).
Since a large portion of the new gas being produced in North America tends to have a significant
level of NGLs, increases in gas production and growth in gas processing capacity has been
closely followed by increases in fractionation capacity, which exceeded 4 million barrels per day
(MMb/d) of capacity in 2012 (for Canada and the US combined), as well as expansions, repurposing, and new construction of NGL gathering (NGLs mix) and delivery (spec product)
systems. Following these developments is expansion in storage facilities and downstream
infrastructure such as an already well-established and large-scale petrochemical industry but
also liquefied petroleum gas (LPG) export terminals as a means to balance markets.
Clearly, the advent of shale gas development in North America has sparked a chain reaction
across the whole NGL value chain from the upstream to the midstream, resulting in significant
levels of infrastructure requirements and associated capital investment.
While the midstream infrastructure in North America is robust, changing dynamics in the
natural gas market have in turn required the evolution of such infrastructure. As producers
focus on their capital-intensive exploration and production (E&P) activities, third-party
midstream players have come forth to finance and build the required processing and marketing
infrastructure. By doing so, these companies are freeing up capital for re-investment and
continued growth in the upstream sector, but also providing a suite of services that allow
producers to maximize their NGL revenues while connecting seamlessly to end-use markets.
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Midstream infrastructure in being commonly built under long-term (10+ years) fee-for-service
agreements, thus creating long-term commitments from producers but leaving them with the
commodity price volatility risk (but also the upside potential). Meanwhile these arrangements
create steady cash flow streams for midstream players, guaranteeing them a level of throughput
necessary to be able to recover investment on their facilities, while allowing them to grow
organically and respond to market needs.
In Canada, NGL midstream investments of close to $11 billion (B) have been made and are
expected to take place between 2011 and 2016, at an approximate average annual rate of
$1.8B. These investments focus on linking increasingly available WCSB NGLs with end-use
markets and are being carried by a handful of companies with expertise and an established
asset footprint. But the midstream industry has also grown through a series of producer-owned
asset divestiture and acquisition of other midstream players and their assets.
The current round of midstream investment in the WCSB includes the building of new gas
plants, pipelines, and fractionators but also the re-furbishing, repurposing, and expansion of
already existing assets. A large portion of this infrastructure is also tied to downstream off-take
agreements from major NGL end-users such as petrochemical producers, but is also supported
by government incentives such as the Government of Alberta’s Incremental Ethane Extraction
Policy (IEEP).
Meanwhile, midstream investments are resulting in downstream investments of close to $4B in
Canada for petrochemical plants and LPG export facilities.
With close to $15B in midstream and downstream infrastructure targeting the monetization of
NGLs in Canada, there is a general feeling that growth is the expected case going forward.
However, the upstream and infrastructure are only one part of the puzzle. Understanding
changes, not only in production, but supply in general, as well as demand, pricing, and
economics will help better identify the different issues at play around NGL markets in Canada, in
North America, and around the globe.
Part III of the NGL update focuses on NGL markets in North America as well as the factors that
are currently shaping those markets. Part IV focuses on global NGL markets.
As upstream activity ramps up and NGLs become increasingly available, infrastructure
investments are being made to get NGLs to market. As local end-use industries face the
possibility of expansion (or even the creation of new value chains) while some other players
look to diversify markets for their output overseas, it becomes increasingly important to have a
clear understanding of local and global NGL markets. These are discussed in Parts III and IV.
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
3
NGL Infrastructure and NGL End-Users
in Canada
While the previous report offered some insight in regards to the different sources of NGL
production in Canada and the US as well as recent trends around natural gas markets in North
America (upstream), this report will focus on the midstream infrastructure required to connect
upstream supplies with markets while identifying some market participants or end-users
(downstream).
The analysis section will cover proposed infrastructure projects and associated investments in
the Canadian midstream and downstream sectors that aim to increasingly bring NGLs to market.
Figure 1.1 serves to illustrate the interactions of NGL supply and demand sources in Canada as
well as their interdependence with other energy markets. Yet the most important feature of
Figure 1.1 is the level of complexity around the midstream and downstream segments of NGL
markets.
This report’s aim is to provide a detailed account of these segments.
Natural Gas Field Processing Plants and Straddle Plants
Field processing plants generally aggregate produced raw gas volumes from various well sites or
producing areas via small diameter raw gas gathering lines and process the gas in order to
remove impurities such as water (H2O)(gas dehydration), carbon dioxide (CO2)(acid gas
sweetening), hydrogen sulfide (H2S)(sour gas sweetening), inert gases such as nitrogen (N2) and
helium (He), but also to extract valuable hydrocarbons such as natural gas liquids (NGLs).
Processing is increasingly done in order to monetize additional commodities (such as NGLs and
sulfur), but its primary purpose is to get the gas to sales gas pipeline quality specifications.1
Once the gas is processed, the resulting sales gas is placed on large diameter gas transmission or
transportation pipelines where it is delivered directly to storage facilities for seasonal
balancing,2 local end-users such as power plants or industrial users, local distribution
companies’ (LDCs) distribution systems for delivery to residential, commercial, and industrial
end-users, as well as to other transmission systems for delivery to export markets.
1
For an example of gas quality pipeline specifications see:
http://www.transcanada.com/customerexpress/docs/assets/Gas_Quality_Specifications_Fact_Sheet.pdf
2
Generally injected in the summer and withdrawn in the winter
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Canadian Energy Research Institute
Figure 1.1: Illustrative Canadian NGL Supply and Demand Flowchart
UPSTREAM (SOURCES)
MIDSTREAM (PROCESSING & TRANSPORTATION)
Transporation
Refineries &
Infrastructure
Upgraders
Crude Oil
DOWNSTREAM (END-USE MARKETS)
Refined Petroleum Products to Markets
Crude Oil &
Condensate
Spec NGLs
~9%
Spec NGLs
Crude Oil & Condensate
Spec NGLs
Fractionators
NGLs Mix
Spec NGLs
Natural Gas
Straddle Plants
~91%
Sales
Gas
Raw Gas
Sales
Gas
Sales Gas to Export Markets
Gas Processing Plants
Sales Gas to Local Markets
Image Sources: Canadian Centre for Energy Information™, Keyera, Imperial Oil, Inter-pipeline Fund, and US Energy Information Administration (EIA). Figure by CERI
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
5
Straddle or gas re-processing plants use economies of scale and location advantages by being
placed on transmission system points where gas from various locations (mainly gas that has
already been processed or sales gas) is aggregated.3 These plants’ function is mainly to remove
NGLs that are left in the sales gas stream.
NGLs recovered from gas processing plants (either as individual specification products but
usually as an NGL mix, depending on the plant’s capabilities) are generally transported via NGL
gathering pipelines to market hubs (for storage), fractionation facilities, delivery to NGL delivery
systems, or delivery to end-users.
Figure 1.2 presents a simplified version of the gas processing and NGL extraction process as
described above. Figure 1.3 illustrates this process with a simplified version of the gas
processing and NGL extraction system in northeastern BC (NE BC).4
Figure 1.2: Gas Processing and NGL Extraction Process
GAS PROCESSING & NGLs EXTRACTION
Wellhead Condensate (C5+)
Spec NGLs
Raw Gas
Raw Gas
Inlet
Separator
Sweet
Raw Gas
Raw Gas
Gathering &
Compression
H2S & CO2
Removal
(Sweetening)
NGLs Mix
Spec NGLs
NGLs
Extraction
NGLs
Markets
Fractionation
Sales Gas to
Market
Sulphur to Market
Acid/ Sour Gas
Disposal
Water
Spec NGLs
Straddle Plant
Source: Images from various sources. Figure by CERI
Starting with the top portion of the chart (Figure 1.3), the brown lines represent the Spectra gas
gathering system (one of the main gathering systems in NE BC), which serves to aggregate raw
gas from various production sites to field gas processing plants (triangles in the chart), such as
those around the Fort St. John area. From the processing plants’ outlets, the sales (or
processed) gas moves on to the transmission system (green lines if moving south/west (local
system), grey lines if moving east to/through AB).
3
Thus these plants are straddling the pipeline system. Hence the name straddle plants
While the transportation system will be furthered discussed in more detail later on, this example is useful to illustrate the
complexity of the required infrastructure to market each commodity
4
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Canadian Energy Research Institute
Figure 1.3: Gas Gathering, Processing, and Transmission System in NE BC (top), Gas
Distribution System (bottom left), and NGL Gathering System (bottom right)
5
6
Sources: Top chart: Spectra Energy /Bottom left: PNG; Bottom right: Pembina Pipelines
7
Once in the transmission system, gas is transported to various delivery points (yellow dots) such
as connections to the TCPL and Alliance pipeline transportation systems (grey lines), power
plants (such as the McMahon cogeneration plant), the Taylor-Younger straddle plant, or to
distribution systems such as the Pacific Northern Gas (PNG) distribution system (Figure 1.3,
bottom left chart). The PNG distribution system delivers sales gas to locations in NE BC
(including Fort St. John, Taylor, and Dawson Creek), but also to the northern interior and
northern coastal regions of BC (yellow line in the bottom left chart).
5
Spectra Energy, West Coast Energy Inc., Commercial Operations Dashboard: https://noms.weipipeline.com/DashBoard/client/index.php
6
Pacific Northern Gas (PNG) website: http://www.png.ca/
7
Pembina Pipelines, About Pembina, Our Business, Conventional Pipelines:
http://www.pembina.com/pembina/webcms.nsf/AllDoc/6FD23EE9B3E2F27F87257B2B0069BFCE/$File/Conventional%20Pipelin
es%20Map%20for%20Website%20-%20Feb%202013.pdf
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Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
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NGLs recovered at NE BC’s field and gas straddle plants (primarily as NGL mixes) are collected on
NGL gathering systems such as the Pembina Peace, Northern, or Liquids Gathering systems
(light blue, yellow, and green lines, respectively, in bottom right chart (Figure 1.3)) in order to be
transported to storage, fractionators, and end-users in the Fort Saskatchewan NGL hub in AB.
CERI estimates that in 2012 there were a total of 706 active field gas processing plants in
Canada. As can be seen in Figure 1.4, the vast majority of these plants are located in the WCSB,
consistent with both natural gas and NGL production.
Figure 1.4: Western Canada Natural Gas Processing and Transportation System (2012)
8
9
10
11
Sources: Data from AER, BCMNGD, CERI research, Industry data, NEB, and OGJ. Figures and tables by CERI
8
AER, Data & Publications, Statistical Reports (ST), ST50: Gas Processing Plants in Alberta & ST13: Alberta Gas Plant/Gas
Gathering System Statistics. Available at: http://www.aer.ca/data-and-publications/statistical-reports
9
In undertaking this research on midstream and downstream infrastructure in Canada, CERI surveyed publicly available
documents such as annual reports, investor presentations, news releases, annual information forms, and websites from
companies that own or operate midstream and downstream assets in Canada including Altagas, ATCO Energy Solutions,
Celanese, CEPSA, Dow chemicals, Gibsons Energy, Enbridge, Imperial Oil, INEOS, Inter-pipeline Fund, Keyera, Kinder Morgan, ME
Global, Nova Chemicals, ParaChem, Pembina Pipelines, Plains Midstream, Selenis, Shell Canada, Spectra Energy, Styrolution,
Unipol, Veresen, and Williams Canada, amongst others
10
NEXT Model Implementation Application, Section 5.0: The Importance of NEXT, NOVA Gas Transmission Ltd.
11
Oil & Gas Journal (OGJ), 2013 Worldwide Gas Processing Survey
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Canadian Energy Research Institute
Together, these plants can process over 30,000 MMcf/d of raw gas. Processing capabilities range
from simple hydrocarbon separators to complex operations designed to form elemental sulfur,
extract and dispose of CO2 and/or H2S, as well as cryogenic deep-cut plants equipped with
turbo-expanders designed for maximum NGL recovery,12 and field plants with not only
extraction capabilities but also on-site fractionation capacity (ability to produce spec NGLs on
site).
Table 1.1 displays facilities that CERI has identified as deep-cut extraction plants in AB, BC, and
SK (WCSB).13
These deep-cut facilities include plants that extract an ethane plus (C2+) NGL mix to be
transported to fractionators in the Fort Saskatchewan area (or used for enhanced oil recovery
[EOR] schemes), but also facilities that extract C2+ mixes and fractionate them (at the field level)
into spec NGLs such as purity C2 to be delivered to markets.14
As can be observed, most of these facilities are located along the Foothills region. Northern
(AB/BC) and plains (mainly SK) regions’ gas plants are generally tied to solution/associated gas
resources. A map of these facilities is provided in Figure 1.5.
Straddle or gas re-processing plants in Western Canada are estimated to have an aggregate inlet
processing capacity of close to 15,000 MMcf/d and are able to extract over 500 kb/d of spec
NGLs and NGL mixes combined (Table 1.2).
These plants vary in size and complexity with the majority of the straddle plant gas processing
capacity clustered at the AB/SK border at Empress (~71 percent), followed by Cochrane (~19
percent), while the remaining 10 percent of straddle plant capacity is located in NE BC and two
locations within AB.
One of the main features of these plants is that they are designed to maximize ethane recovery
from the sales gas (at high efficiencies), primarily in specification, but also in NGL mix form.15
12
The main processes of NGL extraction at processing plants include lean oil absorption, refrigeration, and cryogenic processes.
Recovery efficiencies vary by process with lean oil recovering the least amount of NGLs and cryogenic plants recovering almost
all of the available NGLs in the inlet gas stream
13
AB Facilities were identified as deep-cut based on their authorization to extract C2 or C2+ mixes as per data on the AER ST-50
& ST-13 forms, but also based on Pembina Pipelines system tolls bulletins, and CERI’s Study No. 102: Canadian Natural Gas
Liquids: Market Outlook 2000 – 2010, Louise Gill and Paul Mortensen. April 2001. BC deep-cut plants were identified based on
ethane production volumes as reported by statistics provided by the BCMNGD, assuming all volumes to be in a C2+ mix form as
no connection to the AEGS spec C2 system exists in NE BC. SK deep cut plants information is from the OGJ’s 2013 Worldwide Gas
Processing Survey. (AB deep-cut plants’ capacities are given as the maximum between AER data or maximum volumes extracted
between 2002 and 2012)
14
According to CERI’s analysis, in 2012 only a handful of field plants produced spec C2 to be delivered to market (via AEGS)
including Husky’s Sylvan Lake plant, CNRL’s Knopcik, Shell’s Waterton and Jumping Pound plants, Keyera’s Rimbey Plant, and
Altagas’ Harmattan Complex (considered a straddle plant in CERI’s model and a fractionator by AER since 2012)
15
Mainly, the ATCO Fort Saskatchewan plant
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Natural Gas Liquids (NGLs) in North America – An Update
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Table 1.1: Information on Deep-cut Field Gas Processing Plants in the WCSB (2012)
Plant
ELMWORTH 4-8-70-11W6
SEMCAMS KAYBOB SOUTH #3
SHELL CAROLINE
DEVON ELMWORTH
MUSREAU 4-25-62-6W6
KEYERA STRACHAN 11-35-037-09W5
DEVON DUNVEGAN
HUSKY RAINBOW 10-10
TRILOGY KAYBOB
Encana Resthaven 8-11-60-3W6 GP
CRESTAR WEMBLEY
GORDONDALE GAS PLANT
KEYERA BIGORAY PLANT 10-07-051-09W5
IMPERIAL WEST PEMBINA
ATCO GOLDEN SPIKE
CHEVRON ACHESON
HUSKY BIVOUAC
BONAVISTA CESSFORD
TALISMAN BENSON PEMBINA 08-30
Total Deepcut Plants
ALBERTA DEEP CUT PLANTS
REGULAR DEEP CUT FACILITIES
Gas Processing 2012 Gas
Utilizatio NGLs Extraction
Owner/ Operator
Capacity
Processed
n (%) Capacity (kb/d)
(MMcf/d)
(MMcf/d)
ConocoPhillips Canada (BRC) Partnership
689
328
48%
16
SemCAMS ULC
637
246
39%
66
Shell Canada Energy
364
124
34%
61
Devon Canada
332
309
93%
18
Pembina Gas Services Ltd.
281
200
71%
24
Keyera Energy Ltd.
260
175
67%
21
Devon Canada
227
72
32%
11
Husky Oil Operations Limited
225
122
54%
43
Trilogy Resources Ltd.
201
102
51%
22
Encana Corporation
189
90
48%
15
Conocophillips Canada Energy Partnership
130
61
47%
19
AltaGas Ltd.
114
14
12%
10
Keyera Energy Ltd.
80
29
37%
5
Imperial Oil Resources
74
51
69%
11
ATCO Energy Solutions Ltd.
62
7
12%
3
Penn West Petroleum Ltd.
32
7
21%
4
Husky Oil Operations Limited
28
- n/a
n/a
Journey Energy Inc.
6
1
11%
0
NEP Canada ULC
1
0
19%
0
19
3,932
1,937
49%
349
DEEP CUT FACILITIES WITH FRACTIONATION
Gas Processing 2012 Gas
Utilizatio NGLs Extraction
Plant
Owner/ Operator
Capacity
Processed
n (%) Capacity (kb/d)
(MMcf/d)
(MMcf/d)
SOLEX HARMATTAN-E LKTON
Taylor Processing Inc.
466
167
36%
72
KEYERA HOMEGLEN-RI MBEY 2-05-44-01W5 Keyera Energy Ltd.
400
301
75%
38
SHELL WATERTON
Shell Canada Energy
270
119
44%
15
SHELL JUMPING POUND
Shell Canada Energy
258
126
49%
8
BLAZE BRAZEAU RIVER
Blaze Energy Ltd.
175
62
36%
20
PENGROWTH JUDY CREEK
Pengrowth Energy Corporation
163
37
23%
30
KNOPCIK 9-10-74-11W6
Canadian Natural Resources Limited
67
28
42%
2
CONOCO PECO
ConocoPhillips Canada Resources Corp.
66
44
67%
6
AMOCO WILLESDEN GREEN
Penn West Petroleum Ltd.
57
30
52%
1
RENAISSANCE SYLVAN LAKE-21
Husky Oil Operations Limited
28
13
45%
1
NEWPORT GILBY
Harvest Operations Corp.
19
6
32%
0
MAGIN THREE HILLS CREEK
Penn West Petroleum Ltd.
11
3
28%
1
00/06-15-048-03 W5 Pembina GP
Sinopec Daylight Energy Ltd.
7
5
77%
0
BATTLE 1-24-45-8 W4
Penn West Petroleum Ltd.
2
0
22%
4
Total Deepcut Plants w/ Fractionation
14
1,989
942
47%
198
BRITISH COLUMBIA DEEP CUT PLANTS
Gas Processing 2012 Gas
Utilizatio NGLs Extraction
Capacity
Processed
n (%) Capacity (kb/d)
(MMcf/d)
(MMcf/d)
Spectra Dawson Processing Plant
SPECTRA ENERGY MIDSTREAM CORPORATION
200
40
20% n/a
WEST STODDART
CANADIAN NATURAL RESOURCES LIMITED
120
57
47%
5.5
FARRELL
TALISMAN ENERGY INC.
99
117
118%
0.1
CONOCOPHILLIPS RING C-81-I/94-H-9
CONOCOPHILLIPS CANADA OPERATIONS LTD.
64
40
62%
2.5
DAWSON
ARC RESOURCES LTD.
60
119
198%
0.7
Canbriam Altares
CANBRIAM ENERGY INC.
50
18
36%
1.7
CHINCHAGA
TAQA NORTH LTD.
50
8
17%
0.4
SEPTIMUS
AUX SABLE CANADA LTD.
50
32
65%
1.0
CNRL CLEARHILLS 16-11-88-13 GAS PLANT (AB-XB)
CANADIAN NATURAL RESOURCES LIMITED
46
24
51%
0.5
CARIBOU
KEYERA ENERGY LTD.
40
37
91%
1.0
DUKE GAS PLANT 5-23-80-13 (AB)
SPECTRA ENERGY MIDSTREAM CORPORATION
40
20
51%
0.3
BLAIR
ALTAGAS LTD.
32
29
89%
0.2
PARKLAND
ARC RESOURCES LTD.
28
30
105%
0.9
SUNRISE 3-18-80-17
TOURMALINE OIL CORP.
25
68
272%
1.5
Duke Fourth Creek 16-11-82-09
SPECTRA ENERGY MIDSTREAM CORPORATION
13
10
79%
0.1
SUNSET
SHELL CANADA LIMITED
12
13
105%
0.3
Total
931
663
71%
16.7
Plant
Plant
Steelman
Kisbey
Glen Ewen
Glen Ewen
Lougheed
Total
Owner/ Operator
Owner/ Operator
Plains Midstream
ATCO Midstream
Plains Midstream
Cresecent Point Resources
Arc Energy Trust
SASKATCHEWAN DEEP CUT PLANTS
Gas Processing 2012 Gas
Utilizatio NGLs Extraction
Capacity
Processed
n (%) Capacity (kb/d)
(MMcf/d)
(MMcf/d)
16
13
80% n/a
5
2
40% n/a
3
2
80% n/a
3
2
80% n/a
1
1
80% n/a
28
21
73%
2012 NGLs
(kb/d)
Utilization
2012
(%)
bbl/ MMcf
6
7
8
17
6
7
4
14
1
2
5
1
2
3
0
1
- n/a
0
0
83
2012 NGLs
(kb/d)
22%
69%
26%
61%
22%
25%
100%
32%
76%
65%
37%
8%
100%
0%
34%
3.6
0.3
0.3
0.3
0.4
4.8
PIA14
PIA15
PIA03
PIA14
PIA14
PIA09
PIA17
PIA22
PIA15
PIA13
PIA14
PIA14
PIA10
PIA10
PIA11
PIA11
PIA21
PIA07
PIA11
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Northern
Northern
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Northern
Plains
Foothills
Products
Area
SA
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
PIA03
PIA06
PIA02
PIA03
PIA10
PIA15
PIA14
PIA09
PIA09
PIA06
PIA10
PIA06
PIA11
PIA08
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Plains
Products
Area
SA
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
3 C2+ Mix
0 C2+ Mix
43
94
86
32
40
69
200
64
46
38
57
30
14
32
4
72
Utilization
2012
(%)
bbl/ MMcf
0.1 n/a
1.8
0.1
1.4
0.6
1.0
0.1
0.9
0.3
0.4
0.1
0.2
0.7
1.3
0.1
0.2
9.4
2012 NGLs
(kb/d)
SA
20
29
64
55
32
42
53
113
8
17
74
40
65
53
62
106
n/a
41%
0%
24%
Area
Utilization
2012
(%)
bbl/ MMcf
16
26
4
5
4
7
2
2
1
1
0
0
0
0
68
2012 NGLs
(kb/d)
39%
11%
13%
97%
27%
36%
33%
32%
4%
10%
24%
5%
38%
25%
16%
19%
Products
32%
90%
56%
90%
60%
35%
90%
55%
42%
22%
90%
76%
90%
76%
85%
56%
2
31
1
35
5
57
18
28
11
12
3
7
24
20
5
16
14
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
C2+ Mix
Utilization
2012
(%)
bbl/ MMcf
n/a
n/a
n/a
n/a
n/a
273
126
126
105
503
231
33
34
41
36
33
41
35
32
34
41
33
41
33
33
33
32
Products
Spec C2/ Spec or Mix C3+
Spec C2/ Spec or Mix C3+
C2+ or C3+ Mix
C2+ or C3+ Mix
C2+ or C3+ Mix
Foothills
Foothills
Foothills
Northern
Foothills
Foothills
Northern
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Foothills
Area
SA
56
56
56
56
56
Plains
Plains
Plains
Plains
Plains
Sources: Data from AER, BCMNGD, Industry data, Pembina Pipelines, CERI Research, and OGJ. Tables by CERI
May 2014
10
Canadian Energy Research Institute
Figure 1.5: Map of Deep-cut Field Gas Processing Plants in the WCSB (2012)16
Source: Data from AER, BCMGD, CERI analysis, Industry data, and OGJ. Figure by CERI
16
Plants are shown as red or purple icons, the yellow squares represent CERI’s study areas for the WCSB
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
11
Table 1.2: WCSB Straddle Plant Information (2012)17 (Top), AB Straddle Plants Processing
Volumes (MMcf/d) and Utilization (%) (2002 – 2012) (Bottom)
Owner/ Operator
2012
Processing 2012 Gas
NGLs
Utilization
NGLs Utilization
Capacity Processed
Capacity
(%)
Extracted
(%)
(MMcf/d) (MMcf/d)
(kb/d)
(kb/d)
NGLs
Ownership
Plains Midstream Canada ULC
5,927
1,381
23%
152
49
32%
Spec C2/ C3+ Mix
Empress I: Plains (67%)/ Pembina (33%) / Empress II: IPF (100%)/ Empress V:
IPF (50%)/ Plains (50%)
Spectra Energy Empress Management Inc.
2,279
1,341
59%
58
40
69%
Spec C2/ C3/ C4/ C5
Spectra (92%)/ Pembina (8%)
1195714 Alberta Ltd.
1,193
1,150
96%
78
44
56%
Spec C2/ C3/C4 Mix/ C5+
Pembina (67.5%)/ AltaGas (11.25%)/ Husky (11.25%)/ Devon (10%)
ATCO Energy Solutions Ltd.
1,040
464
45%
14
11
82%
Spec C2/ C3+ Mix
Plains (35.5%)/ ExxonMobil, Shell, & Talisman (15.6%)/ Pembina (12.4%)/
ATCO Midtream (12.2%)/ Devon (10.8%)/ AltaGas (7.2%)/ Nexen (6.3%)
Inter Pipeline Extraction Ltd.
2,363
1,761
75%
120
77
64%
Spec C2/ C3+ Mix
IPF (100%)
Taylor Processing Inc.
466
167
36%
35
21
61%
Spec C2/ C3/ C4/ C5
AltaGas (100%)
AltaGas Ltd.
750
627
84%
30
25
84%
C2+ Mix
Altagas (57%)/ Pembina (43%)
AltaGas Ltd.
369
299
81%
24
13
54%
Spec C2/ C3+ Mix
ATCO Midstream (51%)/ AltaGas (49%)
35
24
69%
2
1
69%
Spec C2/ C3+ Mix
ATCO Midstream (100%)
237
12
5%
13
7
54%
C2+ Mix
AltaGas (100%)
14,659
7,227
49%
526
289
55%
ATCO Energy Solutions Ltd.
AltaGas Ltd.
16,000
80%
14,000
70%
12,000
60%
10,000
50%
8,000
40%
6,000
30%
4,000
20%
2,000
10%
JOFFRE ETHANE EXTRACTION PLANT
ATCO FORT SASKATCHEW AN
AMOCO ELLERSLIE
COCHRANE EXTRACTION PLANT
PANCDN EMPRESS
%
MMcf/d
ATCO MIDSTREAM EMPRESS (3)
PETRO-CAN EMPRESS
AMOCO EMPRESS
Empress
Empress Capacity
AB Straddle Plant Processing Capacity
AB Straddle Plant Processing
Empress Utilization (%)
-
0%
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Straddle Plants Processing Utilization (%)
Source: Data from AER, BCMNGD, Industry data, and NEB. Table and figure by CERI
The Empress and Cochrane straddle plant locations are instrumental as they are located at the
major exporting points for WCSB gas leaving the province to various locations across Canada
and the US. As these export flows have changed over the last decade (particularly at Empress),
so has the utilization of these plants, and their associated NGL extraction.
Fractionators
CERI identifies fractionators at both the field level (gas processing plants with the ability to
extract specification NGL products) as well as stand-alone merchant or third-party fractionators.
The latter type refers to fractionation facilities located at the end of the NGL gathering/delivery
systems, whose purpose is to fractionate various types of NGL mixes (originally extracted at the
field level) into specification products. The underlying trait of both these types of fractionation
plants is their ability to provide NGL specification products ready to be marketed to end-users.
17
Location number refers to the straddle plant’s location on Figure 1.4
May 2014
12
Canadian Energy Research Institute
Table 1.3: Total Canadian Fractionation Capacity (2012) (Top Left)1819 and Fort Saskatchewan
Fractionators NGL Production (kb/d) and Capacity Utilization (%) (2002 – 2012)(Top
Right)/Stand-alone Fractionation Capacity Information (2012) (Bottom)
AB, Field Spec NGL Capacity
AB, Fractionators
AB, Straddle Plants
NE BC, Field Spec NGL Capacity
Subtotal Western Canada
300
100%
268
Capacity (kb/d) % of Total
442
325
180
24
971
40%
29%
16%
2%
88%
250
237
227
217
221
196
200
DFS
216
209
190
192
90%
194
114
19
133
150
10%
2%
12%
80%
75%
1,104
PFS
Total Ft. Sk. Frac. NGLs
70%
Ft. Sk. Fractionation Cap.
50
65%
-
TOTAL CANADA
RFS
85%
100
ON, Sarnia Fractionator
NS, Point Tupper Plant
Subtotal Central/ Eastern Canada
KFS
95%
kb/d
Location, Type
%
Total Canadian Fractionation Capacity
60%
Utilization (%)
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
100%
Canadian Fractionation Capacity (Stand-Alone)
Plant
Owner/ Operator
Capacity (kb/d) 2012 NGLs Output (kb/d) Utilization (%)
Products
Alberta
Fort Saskatchewan
BP Fort Saskatchewan (PFS)
Redwater Fort Saskatchewan (RFS)
Dow Fort Saskatchewan (DFS)
Keyera Fort Saskatchewan (KFS)
Williams Redwater
Subtotal Fort Saskatchewan
Other Alberta
GIBSON HARDISTY
PLAINS BUCK CREEK FRAC PLANT
HIGH PRAIRIE FRACTIONATIO N PLANT
STITTCO KEMP
Subtotal Other Alberta
Total Alberta
Sarnia
Point Tupper (SOEP)
Total Central/ Eastern Canada
TOTAL CANADA
Plains Midstream
Pembina Pipeline Corporation
Dow Chemicals/ Keyera Corp.
Keyera Corp./ Plains Midstream
Williams/ Pembina Pipeline Corporation
114
69
66
30
17
296
77
57
45
31
13
224
68%
82%
69%
104%
78%
76%
Spec NGLs & C3/C4 Mix
C2, C3, C4, C5+
C2, C3, C4, C5+
C3, C4, C5+
C2, C3, C4, C2=, C3=, C4=, Olefinic C5+
Gibson Energy ULC
Plains Midstream Canada ULC
Plains Midstream Canada ULC
Stittco Energy Limited
4
20
5
0.2
29
325
2
1
3
0.2
7
231
54%
4%
73%
100%
23%
71%
C2, C3, C4, C5+
C2, C3, C4, C5+
C3, C4, C5+
C3, C4, C5+
Central/ Eastern Canada
Plains Midstream/ Pembina Pipeline Corporation
114
Exxon Mobil
19
133
95
8
104
84% C3, iC4, nC4, C5+
44% C3, C4, C5+
78%
458
334
73%
Source: Data from AER, BCMNGD, CERI analysis and estimates, Industry data, and OGJ. Table by CERI
As can be observed in Table 1.3, Canada has over 1,100 kb/d of fractionation capacity with the
largest share located in the WCSB. Fort Saskatchewan, AB – located northeast of Edmonton in
the AB industrial heartland (AB NGLs hub) – contains the single largest accumulation of
fractionation (and NGL storage capacity) in one location, and acts as a processing and marketing
hub for NGLs in Western Canada.
18
Capacities for both fractionators as well as NGL pipelines are given as 95% of maximum capacity in most cases
In addition to these, WCSB gas producers have access to two fractionation facilities (along the Enbridge Mainline) located in
Rapid River, MI and Superior, WI in the upper US MW (PADD II) with capacity of over 10kb/d
19
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
13
Production of NGLs from fractionators declined until 2009, at which point it started to increase
again as WCSB gas producers started to make NGLs an important component of their cash flows.
Utilization of fractionators in the Fort Saskatchewan area is increasing rapidly and given the
move from producers to increasingly extract liquids at the field level, expansion of fractionation
facilities in the area are expected in the coming years.
Pipelines and Other Transportation Infrastructure
Natural Gas Transmission and Distribution Systems
Figure 1.6 (top) displays the natural gas transportation infrastructure that connects WCSB gas
producers to various markets across Canada and the United States. The bottom portion displays
the different gas distribution areas and companies across Canada that deliver gas to end-users
(distribution systems).
Figure 1.6: Canadian Natural Gas Transportation Infrastructure (top) and
Distribution Companies/Areas (bottom)
20
Source: CEPA and CGA
20
21
21
Canadian Energy Pipeline Association (CEPA): www.cepa.com
Canadian Gas Association (CGA): www.cga.ca
May 2014
14
Canadian Energy Research Institute
Starting from West to East (top), in BC, the main transportation system is the Spectra Energy
system (light blue lines). This system transports gas primarily produced in NE BC to various
distribution systems within the province including the PNG systems in northern BC, as well as
the Fortis BC distribution system in the lower portion of the province (serving the lower
mainland and Vancouver Island areas).
Meanwhile, gas producers in BC also have access to export markets directly or via the Spectra
system connections to other transportation or transmission systems. These include the Alliance
pipeline system which transports liquids-rich gas from fields in NE BC and NW AB to the US
Midwest (bright red line in top map), the Spectra system connection to the Williams Northwest
pipeline (sales gas) at the Sumas/Huntingdon border crossing at SW BC (connection to pacific
northwest market), and last but not least, the NOVA (TransCanada Pipelines, TCPL) system
(bright blue lines, AB portion), which moves BC and AB sales gas through AB to local markets
and various export point connections.
In AB, TransCanada’s NOVA system22 (bright blue lines within AB) is the main (but not the only)
transportation system available to producers within the province. This system aggregates gas
produced in the various regions of the province, as well as BC gas, and delivers it to distribution
systems within the province, for delivery to residential, commercial, and industrial users (mainly
through the ATCO and Altagas distribution systems), but also directly to industrial users and
power plants.
The NOVA system also connects directly to various export systems, the largest of which is the
TCPL Mainline system at the AB/SK border (Empress/McNeil). The Canadian mainline system
connects WCSB producers to various distribution systems across Canada all the way from SK to
QC including the SaskEnergy (SK), Manitoba Hydro (MB), Union Gas (ON), Enbridge Gas
Distribution (ON), Gazifère (ON/QC), and Gaz Metro (QC)23 distribution systems (Figure 1.6,
bottom).
Along its way, the TCPL Mainline also connects to other (mainly TCPL owned) transportation
systems for deliveries into the US. These include the Great Lakes Gas Transmission/Viking
system (GLGT/Viking) which transports WCSB gas to Eastern Canada (via the Sarnia area, around
the southern section of the Great Lakes, hence its name) and the US Midwest (crossing at
Emerson, MB) (via the Viking system); the Iroquois system which moves gas from the mainline
to the US NE through Waddington, ON; and the Portland system which connects the TQM
system to NE US markets through a crossing at East Hereford, QC.
In addition to the TCPL Mainline, the NOVA system connects WCSB producers to the TCPL
Foothills system. The western section of the foothills system goes from SW AB to a connection
in SE BC at Kingsgate to the GTN pipeline in the US (Idaho). This pipeline moves WCSB and US
Rockies gas to the US Pacific Northwest market.
22
23
Also known as the Nova Gas Transmission Ltd. System (NGTL)
Connection through Trans-Quebec & Maritimes (TQM) pipeline system
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
15
The eastern section of the foothills system goes from SE AB to a crossing in the SK border at
Monchy where it connects to the Northern Border pipeline system (Montana). The Northern
Border system moves WCSB and US Rockies gas through the US Rockies and US Midwest
regions.
Alternatively, producers in BC and AB (and more recently SK as well as North Dakota in the US),
have the option of transporting their gas as liquids-rich gas via the Alliance high vapor pressure
(HVP) pipeline system. This system gathers liquids-rich (wet or hot) gas from the WCSB/Williston
basin (ND) and transports it to the US upper Midwest market (Chicago area), where the NGLs
are extracted and sold to local end-users and where the processed sales gas is sold through
various marketing arrangements.
As can be noted, producers in AB (and the WCSB in general) have a variety of options for
marketing their gas. However, with the export infrastructure exclusively targeting the US
market, the options are dictated by the marginal need for WCSB gas in those US regions that are
accessible via pipelines. As previously discussed (NGLs report update, Part I), given the changing
dynamics of the natural gas market in the US, WCSB producers have experienced rapid changes
in their marketing options and are actively looking for new export markets.
In regards to gas producers in SK, the TransGas system (Figure 1.6 top, turquoise color) connects
producers to the local distribution system (SaskEnergy) as well as to other transportation
systems including the TCPL mainline, the TCPL Foothills system and the Alliance pipeline. Gas
also moves from AB directly to the TransGas system.
The Sable Offshore Energy Project (SOEP) and the Deep Panuke project, both offshore Nova
Scotia, connect to the Maritimes & Northeast (M&NE) pipeline system for deliveries to local
distribution to the Maritime Provinces but mainly the US NE. Gas received at the Canaport LNG
terminal is transported on the Emera New Brunswick pipeline and targets the same
geographical markets.
Liquids Transportation System
Figure 1.7 displays the crude oil/liquids transportation system in Canada and its connections to
various transportation systems in the US. This system is described in detail in CERI Study No.
13324 and therefore will not be discussed here.
The main purpose of the system is to move crude oil from producing areas such as the WCSB to
regional refining hubs including the US West Coast, the US Midwest, Central Canada, and all the
way to the US Gulf Coast.
Figure 1.8 displays NGL gathering and delivery systems in Canada (top) as well as information on
the respective pipeline capacity estimates and the main NGL storage facilities (bottom).
24
Study No. 133: Canadian Oil Sands Supply Costs and Development Projects (2012 – 2046). Available at:
http://ceri.ca/images/stories/2013-06-10_CERI_Study_133_-_Oil_Sands_Update_2012-2046.pdf
May 2014
16
Canadian Energy Research Institute
Figure 1.7: Canadian Crude Oil Pipeline System
Source: CEPA
The most important feature of the top map (Figure 1.8) is the fact that the NGL gathering
systems’ main purpose is to gather liquids (primarily C2+ or C3+ NGL mixes) from hundreds of
plants across BC and AB and deliver them to Ft. Saskatchewan (AB NGL hub) to be fractionated
and marketed.
From the NGL hub, end products (spec NGLs) and NGL mixes move to local markets or export
markets via product delivery systems such as the Cochin pipeline, the Enbridge system, or the
AEGS system.
As NGL extraction at the field level increased over the last few years, the volume of NGL mixes
heading to the Fort Saskatchewan fractionation and marketing hub (AB NGL hub) have
increased. As this trend continues to develop, utilization of the NGL gathering pipeline system
will continue to increase leading to needed expansions (Figure 1.9).25
While it may appear that on an overall system basis there is still some spare capacity, estimating
flows from specific areas of the province through specific NGL systems reveals that some
systems are running at close to capacity.
Thus, increased extraction of NGLs will require investments in pipeline infrastructure expansion
(or additions) which in turn will lead to required expansions at the fractionation facilities. This in
turn presents opportunities for downstream users to increase demand or new markets to
develop via either development of new industries or new export destinations.
25
This is also leading to various recent announcements (ATCO/Petrogas, Keyera, Pembina, and Plains) for NGL storage cavern
expansions primarily around the Ft. Saskatchewan area in Alberta but also at Sarnia, St. Clair, and Windsor in Ontario
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
17
Figure 1.8: Canadian NGL Pipeline Infrastructure (top),26 Capacities (bottom, L) (kb/d), and
Main NGL Storage Facilities and Capacities27,28 (bottom, R) (MMb) (2012)
Boreal
Pipeline
Est. Capacity (kb/d)
Product
Raw Mix Pipelines to Ft. Saskatchewan
Peace HVP System (NGLs)
76 C2+/ C3+
Cochrane-Edmonton (Co-Ed) System
68 C3+
Brazeau NGL Gathering System
57 C2+
Peace LVP System (Condensate)
52 C5+ (Includes Crude)
Northern System
49 C2+/ C3+
Boreal
43 NGLs/ Olefins Mix
Bonnie Glen
33 C5+ (Includes Crude)
Judy Creek
30 C3+
Total Raw Mix Pipelines Est. Capacity
408
Petrochemical Feedstock Pipelines
Alberta Ethane Gathering System (AEGS)
334 Spec C2
Ethylene Delivery System (EDS)
86 Ethylene
Joffre Feedstock Pipeline (JFP)
48 NGLs
NGL Export Pipelines
Enbridge Mainline (Lines 1/5)*
Kerrobert (to Enbridge)
Alliance Pipeline
Cochin Pipeline
Petroleum Transmission Company**
Total NGL Export Pipelines Est. Capacity
127
124
93
71
27
442
C3+ Mixes
C3+ Mixes
NGLs in Gas
Spec C3/ USMW E/P Mix
Spec C3/ C4
171
48
43
59
321
C5+
Spec C2
Spec C2
Spec C2/ Spec C3
NGL Import Pipelines
Southern Lights/ Line 13
Mariner West (Late 2013/ Early 2014)
Vantage Pipeline (2014)
UTOPIA Pipeline (2017-18)***
Total NGL Import Pipelines Est. Capacity
*Net of Kerrobert/ **CERI Estimate/ ***Announced
Storage Facility
Owner/ Operator
Ft. Saskatchewan (AB NGL Hub)
Fort Saskatchewan
Keyera
Redwater
Pembina Pipeline Corporation
Fort Saskatchewan
Plains Midstream
Fort Saskatchewan Joint Venture Veresen Inc./ Plains Midstream
Fort Saskatchewan
Dow/ Keyera Corp.
Alberta Diluent Terminal (ADT) Keyera Corp.
Subtotal Ft. Saskatchewan
Kerrobert
Subtotal Saskatchewan
Products Capacity (MMb)
NGLs
NGLs
NGLs
C2
NGLs
C5+
11
8
4
1
1
0.3
24
Kerrobert, SK
Pembina Pipeline Corporation/ Plains Midstream NGLs
3
3
Total Western Canada
Sarnia
Corunna
Sarnia
Total Ontario
TOTAL CANADA
26
Ontario
Pembina Pipeline Corporation/ Plains Midstream Spec NGLs
Pembina Pipeline Corporation
NGL Mix
Pembina Pipeline Corporation/ Plains Midstream NGL Mix
6
5
2
13
39
Source: Data from AER, Industry data, and CERI research. Figure and tables by CERI
26
Intra-AB diluent pipelines (oil sands operations) not included. These pipelines are discussed in Study No. 133
Please note that the storage estimates are derived based on a review of companies’ investor reports and consist primarily of
underground salt cavern storage facilities, thus not reflecting all the available above-ground or secondary storage. Furthermore,
diluent storage is often associated with crude oil storage and transportation operations and such operations were not surveyed.
The estimates provided in this table are by no means all inclusive and CERI acknowledges that the storage capacity might be
larger than estimated. Yet, based on the largest midstream players in Canada, CERI believes the given estimate to be
conservative but reasonable.
28
Note that some of the storage facilities listed above can also be used for storing other liquid hydrocarbons such as ethylene,
condensate/pentanes plus, as well as crude oil
27
May 2014
18
Canadian Energy Research Institute
Figure 1.9: NGLs Transported to Fort Saskatchewan and Pipeline Capacity (L) and Peace LVP
System Throughput Estimates and Capacity (R) (kb/d) (2002 - 2012)
450
100%
400
90%
350
80%
BC NGL Mixes
70%
Straddle Plants NGL Mixes (Exc. Empress)
60%
250
50%
200
150
40%
AB Field NGL Mixes
30%
Pipeline Capacity to Ft. Sk.
100
20%
50
10%
-
C5+/ Condensate
%
kb/d
300
Off-Gas SGL Mixes
0%
Total Liquids to Ft. Sk.
Utilization (%)
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
80
100%
70
95%
60
90%
40
%
kb/d
50
85%
30
20
10
BC Plants NGL Mixes
AB Plants NGL Mixes
System Capacity
Total
Utilization (%)
-
80%
75%
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Source: Data from AER, BCMNGD, CERI estimates, and Pembina Pipelines. Figures by CERI
In regards to spec products, ethane recovered at the straddle plants at Empress, Cochrane, and
other locations in AB, as well as ethane from field plants and the Fort Saskatchewan
fractionators,29 gets delivered to the Alberta Ethane Gathering System (AEGS).30
This system, owned by Veresen (formerly Fort Chicago31) and operated by Nova Chemicals,
delivers specification ethane to petrochemical facilities at Joffre (east of Red Deer)(Nova
Chemicals/Dow Chemicals) and at Ft. Saskatchewan (Dow Chemicals).
29
Which are fed via NGL gathering systems from various points in the province (C2+ Mixes)
Spec ethane dedicated system
31
Veresen is a part owner of the Alliance Pipeline which originates In Ft. St. John, BC, as well as a large scale extraction and
fractionation plant at the main delivery point near Chicago, Ill (operated by Aux Sable)
30
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
19
Starting in mid-2014, the Vantage Pipeline (45 kb/d of initial capacity32) will bring in ethane
from the Bakken formation (Williston basin in North Dakota) to AB petrochemical users through
a connection to the AEGS system at Empress. This ethane is extracted from the associated gas
produced with the increasing volumes of light crude oil output in the area.
Meanwhile, as of late 2013/early 2014, the Mariner West pipeline supplies the Sarnia
petrochemical market with ethane from the Marcellus and Utica basins in the US NE/Upper
Midwest (50 kb/d of initial capacity), while the Cochin pipeline has been moving an 80 percent
ethane/20 percent propane (E/P) mix from the US Midwest’s NGL hub at Conway (KS) to the
Sarnia area.33
Additionally, Kinder Morgan and Nova Chemicals recently announced their intent to build an
ethane/propane pipeline from Ohio’s Utica shale to the Sarnia area (the Utica to Ontario
Pipeline Access or UTOPIA pipeline)34 with a target capacity of between 50 and 75 kb/d and a
start date of late 2017.35
These are all clear examples of how changes in natural gas36 dynamics are translating into
changes in NGL supply and demand dynamics, required infrastructure build-outs, as well as
expansions in some downstream markets (primarily petrochemicals, as discussed in the next
section).
Back in AB, the ethylene delivery system (EDS) serves to move ethylene produced at Nova’s
Joffre (AB) site to various customers and petrochemical derivative plants around the Joffre and
Ft. Saskatchewan areas. The Joffre feedstock pipeline (JFP)37 provides the Joffre site access to
ethylene cracking petrochemical feedstock other than ethane (primarily propane) for its
operations as needed. The JFP is also used to transport ethane/ethylene from Williams’ NGLs/
olefins fractionator in the Ft. Saskatchewan area to Joffre.
Aside from local heating, refining, solvent, diluent, and petrochemical markets, the main outlets
for WCSB propane and butanes (in regards to pipelines) include the Cochin pipeline38 (to
Ontario and the US Midwest markets), as well as the Petroleum Transmission Company (PTC)
pipeline which serves the SK and MB markets.
32
Expandable to over 60 kb/d of capacity
This is likely to cease past mid-2014 after the Cochin pipeline is reversed and put into diluent service
34
The pipeline will connect at Michigan to the existing Cochin segment which flows east to the Sarnia area
35
Kinder Morgan Energy Partners Announces Letter of Intent with NOVA Chemicals Corporation for New Utica to Ontario
Pipeline: http://phx.corporate-ir.net/phoenix.zhtml?c=93621&p=irol-newsArticle&ID=1885037&highlight=
36
And to some extent crude oil
37
EDS and JFP are operated by Altagas
38
Spec C3 only. Will be reversed and placed into diluent service for oil sands producers starting in mid-2014. Prior to 2009,
Cochin also shipped ethane and ethylene from AB to ON in addition to propane.
33
May 2014
20
Canadian Energy Research Institute
Enbridge’s Lines 1/5 transport an NGL mix (primarily C3/C4)39 which originates at Ft.
Saskatchewan,40 Empress,41 and Cromer (MB), to be delivered to fractionators in Sarnia and the
US Midwest.42
The fractionated products (primarily C3 and C4s) are used at the Sarnia petrochemical market
but also satisfy local heating and refining markets as well as exports to the US Midwest and East
Coast (PADDs II and I).
From the Sarnia market (but also from the Ft. Saskatchewan market), propane and butanes
move primarily via railway, pipelines, and trucks. Railway and truck transportation are in fact
popular transportation options for these NGLs.
The National Energy Board’s (NEB) NGL disposition data43 indicates that in 2012, of the close to
100 kb/d of propane exported from Canada to the US, over 60 percent was transported via
railway,44 less than 30 percent was transported via pipeline,45 followed by trucks at less than 10
percent. Meanwhile, of the close to 25 kb/d of butanes exported to the US in 2012, about 15
percent was moved via pipeline while the remaining 85 percent was primarily moved via rail.
Thus, rail transportation plays an important role in moving propane and butanes (together, LPG)
out of Western and Central Canada46 to various US markets.47,48
Pentanes plus and condensate (the main oil sands diluents) move from as far as the US Gulf
Coast to the AB market via connections to the Southern Lights/Line 13 pipeline system but also
via rail cars from the US Midwest and other areas. Cenovus operates a marine terminal in
Kitimat, BC49 from where overseas diluent moves via rail to its operations in NE AB.
Starting in mid-2014, the Cochin pipeline will be reversed and will be put into diluent service,
transporting diluent sourced from various connection points across Kinder Morgan’s midstream
assets in the US to the AB diluent market.
Inside the province, most conventional crude oil transportation systems as well as some of the
NGL gathering systems, combined with rail and truck transport, move diluent to the Edmonton
and Hardisty markets.
39
CERI estimates that some minor C5+ volumes are also delivered on this system
Main source is estimated to be the Plains Midstream Fort Saskatchewan (PFS) Fractionator
41
NGL mixes from straddle plants via the Kerrobert pipeline
42
Rapid River, MI fractionator and Superior, WI de-propanizer
43
NEB, Statistics, Natural Gas Liquids (NGL) Statistics: http://www.neb-one.gc.ca/CommodityStatistics/?language=english
44
Primarily from ON (to PADDs II and I), AB (PADDs IV, and V), and QC (PADD I)
45
Primarily via the Cochin pipeline but also small volumes via pipeline from ON to the upper Midwest (WI)
46
Ontario & Quebec
47
The most important US markets for these products are PADDs I, II, and V in that order
48
Assuming a capacity of 750 bbl/car for pressure-rated tank cars that can carry propane and butanes, as well as an average of 2
round trips per month (365/12/2= 15.2 days), the annual average 82 kb/d of propane (61 kb/d) and butanes (21 kb/d)
(combined) transported via rail in 2012 implies that there were at least (82,000 b/d x 15.2d / 750 b/car) ~1,662 pressure-rated
tank cars moving NGLs sourced from the WCSB to other markets
49
Originally, purchased from Methanex and recently sold to Shell as they contemplate BC LNG export plans
40
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
21
Meanwhile, these products move from the main condensate pools to oil sands projects via
regional pipelines, rail, and truck. Once diluted, dilbit (diluted bitumen) and synbit blends
(synthetic bitumen, a blend of SCO and crude bitumen) move mainly through the crude oil
pipeline transportation system50 to various markets, primarily across North America.
While not considered a liquids pipeline system, the Alliance system transports NGLs in gas phase
from the WCSB51 to the US Upper Midwest market (Chicago area). This provides producers with
an option to ship gas with entrained NGLs to the US Midwest market and receive a price that
reflects the price of those commodities while sharing the profits with the infrastructure owners.
CERI estimates52 that the Alliance system transports close to 100 kb/d of NGLs in gas phase, out
of which about 68 percent is ethane, 21 percent propane, 7 percent butanes, and 4 percent
pentanes plus. This, however, does not mean that all these liquids are recovered at Aux Sable’s
(Channahon, IL) plant due to sales gas heating value requirements and liquid extraction
efficiencies. This plant’s output is estimated to be around 90 kb/d of spec NGLs.
Last but not least, the NGL storage system serves to balance seasonal fluctuations in demand
for both NGL mixes and spec products. These sites are usually located close to fractionation
plants (NGLs mix storage) or end-users (spec product storage) and have access to different
pipeline systems as well as rail and truck loading racks in order to deliver products to markets as
needed.
CERI estimates that approximately two thirds of the main NGL storage capacity is located in
Western Canada, with the majority of these facilities located around Ft. Saskatchewan. The
remaining one-third is located around the Sarnia area.
Rail Transportation Infrastructure
As discussed above, rail transportation plays an important role in moving WCSB NGLs to end
users. Propane and butanes (as well as various RPPs and chemicals) are moved from the WCSB
and Central Canada to various locations across North America, while diluent is moved from
various locations in the US to oil sands producers in AB.
Given recent and continuously expected bottlenecks in the crude oil pipeline transportation
system out of the WCSB, several crude by rail terminals are being built and proposed in Western
Canada to provide producers with new marketing outlets.53
50
But also through rail cars, a means to transport crude oil which continues to gain market share
Alliance pipeline also serves the US Bakken area around North Dakota
52
Based on October 30, 2013’s average Canadian gas receipts composition and 2012’s annual receipt volumes in Canada (or
about 62 bbl/MMcf)
53
Some estimates indicate that over 700 kb/d of rail loading capacity can be developed over the coming years. See:
http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/proposed-projects-to-boost-railterminal-oil-capacity/article13711526/?from=13711508. CERI’s crude by rail database estimates indicate that by the end of
2013 over 1,000 kb/d of crude by rail loading capacity out of Western Canada had been proposed. This in turn means over 1,000
kb/d of potential diluent haul-backs. Even if just a fraction of that capacity is used for haul-backs it still represents significant
transportation infrastructure available for diluent delivery to the AB oil sands market
51
May 2014
22
Canadian Energy Research Institute
In the context of NGL markets, this development is important as it presents the opportunity for
diluent haul-backs. That is, once the crude is delivered from Western Canada to a refining
center in North America, the rail cars can be loaded with diluent (pentanes plus/condensate)
destined to the Alberta market. Alternatively, the possibility to ship bitumen as rail-bit or clean
bitumen on rail cars,54 could lead to significant reductions in the expected demand for diluent at
oil sands operations.
Rail transport provides a more flexible, scalable and quicker-to-deploy transport option for NGL
marketers with the added advantage that more locations can be reached55 (including the US
Gulf Coast).56 Figure 1.10 displays North America’s rail network for illustration purposes.
Figure 1.10: North America's Rail Transportation Network
Source: AAR
57
The main railway companies operating in Western Canada are Canadian Pacific (CP) and
Canadian National (CN). Both of these companies have access to the Fort Saskatchewan area
(AB NGL hub).
Table 1.4 displays some of the main rail NGL handling facilities (top) as well as the estimated
fleet of NGL rail cars from some major Canadian NGL midstream and logistics companies.
54
Rail-bit usually requires less than 20% diluent by volume compared to about 30% for dilbit. Clean bitumen requires no diluent
but requires coiled and insulated (C&I) cars for transport and steam facilities for offloading
55
Rail transport has also become a viable option for transporting crude oil across North America as pipeline infrastructure
requires large capital investment, has longer lead times as well as more regulatory hurdles to clear
56
North America’s major NGL marketing, and more recently, export hub, for which no direct pipeline connection from Western
Canada exists
57
Association of American Railroads (AAR), Moving Crude Oil by Rail, May 2013:
https://www.aar.org/keyissues/Documents/Background-Papers/Crude-oil-by-rail.pdf
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
23
Table 1.4: Large Canadian Midstream Companies NGL Rail Handling Facilities58 (top) and
Rail Car Fleet59 (bottom) (2012)
Facility
Redwater
Alberta Diluent Terminal (ADT)
Edmonton Terminal
Rimbey Rail Terminal
Gilby and Nevis Rail Terminals
Sarnia/ St. Clair/ Windsor
Total
Onwer/ Operator
Pembina Pipeline Corporation
Keyera Corp.
Keyera Corp.
Keyera Corp.
Keyera Corp.
Pembina/ Plains
Type
C5+ rail off load facility
C5+ rail off load
C3,C4, C5+ loading/ offloading
C3, C4, C5 loading
C3, C4, C5 loading
C3, C4, C5 loading
Capacity (kb/d)
75
50
34
13
7
45
225
Location
AB NGL Hub
AB NGL Hub
AB NGL Hub
WCSB
WCSB
Southern ON
Facility
NGLs Infrastructure
NGLs Infrastructure
Redwater Rail Cars
Empress/ Sarnia Rail Cars
LPG Railcars
Total
Onwer/ Operator
Altagas Corp./ Petrogas
Keyera Corp.
Pembina Pipeline Corporation
Pembina Pipeline Corporation
Gibsons Energy
Type
NGLs Rail Cars
NGLs Rail Cars
NGLs Rail Cars
NGLs Rail Cars
NGLs Rail Cars
# of Railcars
1,500
1,300
700
300
500
4,300
Location
WCSB/ US
AB NGL Hub
AB NGL Hub
AB NGL Hub/ ON
WCSB/ US
Sources: Industry data and CERI estimates and research. Tables by CERI
As can be observed (Table 1.4, top) there are approximately 225 kb/d of NGL handling capacity
in Canada. Including the Redwater, ADT, and Edmonton Terminal facilities, there is capacity to
offload about 160 kb/d of diluent in the AB market via rail (in addition to 170 kb/d of pipeline
capacity on Southern Lights). Meanwhile, the Edmonton Terminal, together with the Rimbey,
Gilby, Nevis, and Southern Ontario terminals represent the ability to move close to 60 kb/d of
spec NGLs from Western Canada to other markets.
Furthermore, the 4,300 rail cars transporting Canadian NGLs (Table 1.4, bottom) represent over
200 kb/d of NGL transportation capacity (212 kb/d) assuming 750 bbl/car capacity and two
roundtrips per month.60
By any measure, the rail transporation infrastructure is an important component of the logistics
network for delivering Canadian NGLs to market and transporting diluent to oil sands
operations.
Refineries, Upgraders, and Off-gas Processing Plants
Table 1.5 displays refining capacity by location across Canada as well as oil sands upgraders in
the WCSB (top). The bottom portion of Table 1.5 lists the two currently existing off-gas
processing and SGLs extraction plants in AB.
58
Based on the NEB’s NGL disposition data for 2002 to 2012, CERI estimates LPG rail loading capacity to be at least 100 kb/d in
Canada with about 45 kb/d in Western Canada and 55 kb/d in Eastern Canada
59
In addition to these, other midstream companies such as Plains Midstream are known to have a large fleet on LPG rail cars.
Wholesale and retail distributors like CanWest Propane (Gibsons), Superior Propane, and Parkland fuels are also known to have
LPG rail car fleets. After accounting for those, the total number of LPG cars is estimated to be at least 4,500 - 5,000
60
See note 48 for sample calculation
May 2014
24
Canadian Energy Research Institute
Table 1.5: Canadian Refining and Upgrading Capacity (top) (kb/d), and Off-gas
Processing Plants (bottom) (2012)
Location
Atlantic Canada
Ontario
Alberta
Quebec
BC & SK
Total Canada
# of
Upgrader
Refining Capacity (kb/d) Refineries Suncor Base + Millenium
499
3 Syncrude Mildred Lake
475
5 AOSP - Shell Scotford
451
3 Nexen Long Lake
402
2 CNRL Horizon
304
5 Husky Lloydminster
2,130
18 Total Upgrading Capacity
Bitumen Capacity (kb/d)
Location
Ft. Mc Murray
440
Ft. Mc Murray
407
Ft. Saskatchewan
255
Ft. Mc Murray
72
Ft. Mc Murray
141
Lloydminster AB/ SK
96
1,411
Off-Gas Processing Plants
Plant
Owner/ Operator Capacity (MMcf/d)
Output
Aux Sable Heartland Off-gas Plant
Veresen/ Enbridge 20 MMcf/d
C2, C3+, H2
Williams Ft. McMurray Off-gas Plant (Suncor) Williams
125 MMcf/d & ~18 kb/d NGLS/ Olefins Mix NGLS/ Olefins
Location
AB Industrial Heartland
Fort McMurray
Source: Data from ADOE, CAPP, Industry data and Husky. Tables by CERI
As can be observed, the vast majority of refining capacity is located in Central and Atlantic
Canada due to its close proximity to large demand centers and access to export markets.
Upgrading capacity is located around the oil sands developments as the process yields a
commodity (SCO) which is easier to transport and market in local and export markets. Off-gas
processing plants are located at crude bitumen upgrading sites.
Refining capacity and RPPs production is important in the context of NGL production because of
the production of LPGs as discussed in the upstream report (Part I). Refineries are also endusers of butanes for gasoline blending purposes. Furthermore, there are some integrated
refining and petrochemical complexes across Canada that are important users of crude oil and
NGLs but also produce various types of petrochemical feedstock as well as chemicals and
finished products.
Meanwhile, upgraders and off-gas processing plants are relevant in this context because they
are a potential source of NGLs through extraction of SGLs from off-gases.
Petrochemical Facilities: Steam Crackers (Olefins Plants), Aromatic
Plants, Derivative Plants, and Others
Figure 1.11 provides a simplified flow diagram of petrochemical feedstock sources and end
products.
As can be observed, the petrochemical industry provides an important link between
hydrocarbon producers and finished goods by transforming natural resources to end-use
manufactured consumer products for everyday needs. By doing so, the petrochemical industry
adds incremental economic value to those hydrocarbon resources. This point is further
illustrated in Figure 1.12.
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
25
Figure 1.11: Petrochemical Feedstock and End-use Flowchart (simplified)
Source: International Energy Agency (IEA)
61
Figure 1.12: Moving Up the Value Chain from Hydrocarbons to End-use Products
(2012 prices $/t)62
-
2
LDPE Film
$2,246
HDPE Injection Molding
$2,225
HDPE Blow Molding
$2,202
LLDPE-Octene-1Film
$2,154
LLDPE-Hexene-1Film
$2,133
4
6
8
Value Multiplier (x times)
10
12
18
18
Propylene (Polymer Grade)
$1,309
11
$1,305
11
Product
$2,045
18
17
$1,099
$992
Furnace Oil
$964
Pentanes Plus
$900
Butanes
$847
Light Sweet Crude
$843
Propane
$407
Ethane
$229
Natural Gas
$120
0
20
19
$2,114
Gasoline
18
18
HDPE HMW Film
Kerosene
16
19
LLDPE-Butene-1Film
Ethylene
14
9
8
8
8
Upgrading natural gas and NGLs to various
forms of plastics and consumer products adds
significant incremental economic value
7
7
3
2
1
500
1,000
1,500
2,000
2,500
$/ t
63
Source: Data from ADOE, EIA, the Kent Group, and Dewitt & Company. Figure by CERI
61
International Energy Outlook, World Energy Outlook 2013. Available at:
http://www.worldenergyoutlook.org/publications/weo-2013/
62
HDPE: High density polyethylene/LDPE: Low density polyethylene/LLDPE: Linear low density polyethylene
63
Petrochemical Portal: http://www.dewittworld.com/portal/Default.aspx
May 2014
26
Canadian Energy Research Institute
In the Canadian context the main sources of petrochemical feedstock include NGLs from
processing plants and off-gas plants as a feedstock for olefin or ethylene crackers in AB
(primarily C2 with some minor C3 volumes) and ON (C2 to C5s) as well as crude bitumen, crude
oil, and condensates processed at refineries which yield LPG’s, as well as refinery naphtha and
gas oils which are also used as feedstock for steam crackers (to produce olefins).
Both refineries and steam crackers produce olefins (such as ethylene and propylene) as well as
aromatics (such as benzene, toluene, and xylenes (BTX)) and other co-products. Thus, the
primary types of petrochemical facilities in Canada include olefin (or steam) crackers and
refineries (aromatics plants).
The primary output from olefin plants (steam or ethylene crackers) is ethylene. However, the
steam cracking process also yields a variety of co-products including propylene, butylene,
butadiene, fuel gas, and pyrolysis gasoline (naphtha range liquid hydrocarbons with a high BTX
content) among others. Generally, the lighter the feedstock (e.g., ethane and propane) the
higher the ethylene yield from steam cracking and the lower the co-product yield.
Ethylene and co-products are then used as feedstock in derivative plants to make end-use
products. Some co-products can be used as finished products such as propylene and BTX for
gasoline blending. However, ethylene (generally produced in gas form), similar to ethane, is
neither easy to transport (other than via high vapor pressure pipelines) nor store (compressed
gas into liquid form), and generally tends to be turned into other products (such as
polyethylene, ethylene glycol, styrene monomer, and others) on site and as such ethylene
crackers are usually built in conjunction (or downstream integrated with) ethylene derivative
plants.
The primary output from refineries is refined petroleum products such as gasoline and diesel.
However, refineries also produce LPGs, naphtha and gas oils, which can be used as a feedstock
for steam crackers, while also producing propylene and BTXs which can be used in derivative
plants or as gasoline blend stock.
BTXs can also be used for the manufacturing of styrene monomer, solvents, paints, pesticides,
and other finished products. Refineries’ BTX yields will depend on the refinery configuration and
their crude slate (diet) as well as their downstream integration to chemical complexes.
Table 1.6 displays Canadian olefin facilities together with the respective ethylene derivative
plants (those facilities which use ethylene as their main petrochemical feedstock). Table 1.6 also
displays aromatic plants (as parts of refining complexes) from where BTX is produced for enduse products.
One of the main links between these two types of facilities (olefin and aromatics chains) is the
styrene monomer (SM) plants which manufacture styrene by dehydrogenation of ethylbenzene which is initially produced by synthesizing ethylene (sourced primarily from olefin
crackers) and benzene (produced primarily from refineries but also from steam crackers).
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
27
Table 1.6: Canadian Petrochemical Plant Information (2012)
ALBERTA
Company
Facility
Location
Main Product
Ethylene Crackers (Olefins)
NOVA Chemicals
NOVA Chemicals
NOVA Chemicals (50%)/ Dow Chemicals (50%)
Dow Chemicals
Total Ethylene Crackers
Ethylene 1 (E1)
Ethylene 2 (E2)
Ethylene 3 (E3)
Dow Fort Saskatchewan (LHC1)
Joffre Complex, AB
Joffre Complex, AB
Joffre Complex, AB
Fort Saskatchewan, AB
Ethylene
Ethylene
Ethylene
Ethylene
Aromatics Plants
Shell Canada
Total Aromatics
Shell Scotford Refinery
Scotford, AB
Benzene
Plant
Capacity
(kt/yr)
726
816
1,270
1,285
4,097
Feedstock
Required
Feedstock (kb/d)
C2/ Some C3
C2/ Some C3
C2
C2
370 Crude Oil
370
45
51
79
80
255
n/a
Ethylene Derivatives
Polyethylene and Similar Products
NOVA Chemicals
NOVA Chemicals
INEOS Oligomers
Dow Chemicals
Dow Chemicals
Celanese (AT Plastics)
Total
Ethylene Glycol
ME Global (50% owned by Dow Chemicals)
ME Global (50% owned by Dow Chemicals)
ME Global (50% owned by Dow Chemicals)
Shell Chemicals Canada Ltd.
Total
Styrene Monomer
Shell Chemicals Canada Ltd.
Required
Feedstock (kt/yr)
Polyethylene 1 (PE1)
Polyethylene 2 (PE2)
Joffre Linear Alpha Olefins (LAO) Plant
Prentiss PE
Fort Saskatchewan PE
Edmonton EVA Manufacturing Plant
Joffre Complex, AB
Joffre Complex, AB
Joffre Complex, AB
Red Deer, AB
Fort Saskatchewan, AB
Edmonton, AB
LLDPE
LLDPE & HDPE
LAO
LLDPE
LLDPE
LDPE, EVA
Prentiss I Ethylene Oxide/ Ethylene Glycol (EO/EG) Plant
Prentiss II EO/EG Plant
Fort Saskatchewan (FS) 1EO/ EG Plant
Shell Chemicals Scotford Manufacturing Monoethylene Glycol (MEG)
Plant
Red Deer, AB
Red Deer, AB
Fort Saskatchewan, AB
MEG
MEG
EO/EG
Scotford, AB
MEG
Ethylene
Ethylene
Ethylene
Ethylene
Ethylene
Ethylene
678
435
253
505
859
61
2,790
310 Ethylene
285 Ethylene
350 Ethylene
179
165
202
450 Ethylene
1,395
260
806
Shell Chemicals Scotford Manufacturing Styrene Monomer (SM) Plant
Scotford, AB
SM
450 Ethylene
Benzene
450
121
365
486
Alberta EnviroFuels (AEF)
Redwater Fractionator/ Propylene Plant
Edmonton, AB
Redwater, AB
Iso-octane
PGP
521 Field Butanes (f-C4)
68 SGLs Mix
589
Total
Other Facilities
Keyera Corp.
Williams Canada
Total
671
431
250
500
850
143
2,845
n/a
n/a
ONTARIO
Company
Facility
Location
Main Product
Plant
Capacity
(kt/yr)
Feedstock
Required
Feedstock (kb/d)
Ethylene Crackers (Olefins)
NOVA Chemicals
Imperial Oil Products & Chemicals
Total Ethylene Crackers
Aromatics Plants
Benzene
Imperial Oil
Nova Chemicals
Shell
Sunoco Chemicals (Suncor)
Total Benzene
Toluene
Imperial Oil
Shell
Sunoco Chemicals (Suncor)
Total Toluene
Ethylene Derivatives
Polyethylene and Similar Products
NOVA Chemicals
NOVA Chemicals
NOVA Chemicals
Imperial Oil Products & Chemicals
Total
Styrene Monomer
Styrolution
Corunna, Ethylene
Imperial Sarnia
Corunna, ON
Sarnia, ON
Ethylene
Ethylene
839 C2,C3,C4,C5+
300 C2,C3,C4,C5+
1,139
67
23
90
Imperial Sarnia
Corunna, Ethylene
Shell Sarnia
Suncor Sarnia
Corunna, ON
Sarnia, ON
Sarnia, ON
Sarnia, ON
Benzene
Benzene
Benzene
Benzene
110
120
60
50
340
Crude Oil/ NGLs
Crude Oil/ NGLs
Crude Oil
Crude Oil
n/a
n/a
n/a
n/a
Imperial Sarnia
Shell Sarnia
Suncor Sarnia
Sarnia, ON
Sarnia, ON
Sarnia, ON
Toluene
Toluene
Toluene
85 Crude Oil/ NGLs
130 Crude Oil
207 Crude Oil
422
n/a
n/a
n/a
Required
Feedstock (kt/yr)
St. Clair River, Corunna, ON PE
Mooretown, ON PE
Mooretown, ON PE
Sarnia PE
Corunna, ON
Mooretown, ON
Mooretown, ON
Sarnia, ON
HDPE
HDPE
LDPE
HDPE
Styrolution Sarnia Production Site
Sarnia, ON
SM
Total
204
211
170
470
1,055
Ethylene
Ethylene
Ethylene
Ethylene
194
200
161
446
1,002
431 Ethylene
Benzene
431
116
339
455
Other Facilities
Lanxess Inc.
Total
Sarnia Site
Sarnia, ON
Butyl Rubber
Mixed C4's, Butylene,
Butadiene, Styrene,
150 Other
n/a
150
May 2014
28
Canadian Energy Research Institute
QUEBEC
Company
Facility
Aromatics Plants
Benzene
Suncor
Total
Toluene
Suncor
Total
Other Facilities
Aromatics Derivatives
p-Xylene
ParaChem Chemicals (Suncor)
Total
Xylene/PTA Derivatives
Interquisa Canada (CEPSA Chimie)
Selenis
64
Location
Main Product
Plant
Capacity
(kt/yr)
Feedstock
Required
Feedstock (kt/yr)
Suncor Refinery/ Petrochemicals
Montreal, QC
Benzene
350 Crude Oil
350
n/a
Suncor Refinery/ Petrochemicals
Montreal, QC
Toluene
240 Crude Oil
240
n/a
Montreal Site
Montreal, QC
p-Xylene
350 Benzene & Toluene
350
n/a
Montreal Site
Montreal Site
Montreal, QC
Montreal, QC
PTA
PET
500 p-Xylene
150 PTA
65
66
67
68
350
345
69
Sources: Data from AED, AIEM, BMI, CERI research, MEI, Industry data, OGJ data, and Sarnia-Lambton Economic
70
Partnership. Tables by CERI
Table 1.7 provides a summary of the three major Canadian petrochemical clusters and the
interaction between the steam crackers, aromatic plants (refinery complexes), and their
derivative plants.
Starting with the ethylene crackers, it can be observed that about 78 percent of the ethylene
cracking capacity is located in AB, with the largest concentration of capacity around the Joffre
complex. All ethylene crackers combined have the potential to use a total of about 342 kb/d of
NGLs and heavier feedstock71 (about 255 kb/d in AB, and about 87 kb/d in ON). In turn, these
facilities have the capacity to produce a total of 11.5 billion pounds (Blbs) (or about 5,236
thousand tonnes (kt))72 of ethylene per year. Estimated co-product capacity for these facilities is
over 4.4 Blbs (or 2,003 kt) per year.73
64
Alberta Chemical Operations, Alberta Economic Development (AED), May, 2000:
http://www.nelson.com/albertascience/0176289305/student/weblinks/documents/ChemicalOperationsDirectory.pdf
65
Association Industrielle de l’est de Montreal (AIEM), Membres et types d’industries:
http://www.aiem.qc.ca/index.php?option=content&task=view&id=11&Itemid=106
66
Business Monitor International (BMI), Canada Petrochemicals Report, 2013: http://www.marketresearch.com/BusinessMonitor-International-v304/Canada-Petrochemicals-7287960/
67
Including: Canadian Energy Research Institute (CERI): The Sarnia Complex, Synergies and Strategies, Study No. 68. December,
1995
68
Montreal Economic Institute (MEI), the Economic Benefits of Pipeline Projects to Eastern Canada:
http://www.iedm.org/files/note0813_en.pdf
69
Oil & Gas Journal (OGJ), International Survey of Ethylene From Steam Crackers – 2013:
http://www.ogj.com/articles/print/volume-111/issue-7/special-report-ethylene-report/international-survey-of-ethylenefrom.html
70
Sarnia-Lambton Petrochemical and Refining Complex, October 2013:
http://www.sarnialambton.on.ca/medialibrary/5/S_L_PETROCHEM_BROCH.pdf
71
Based on OGJ data for the start of 2013, the feedstock requirement based on capacity is about 274 kb/d of ethane, 28 kb/d of
propane, 20 kb/d of butane, and 19 kb/d of Naphtha, for a total of 342 kb/d of ethylene cracking feedstock. Capacity of the ON
steam crackers varies based on the feedstock mix.
72
There are 2,205 lbs in a metric ton or tonne (t)
73
Net of BTX as listed in Table 1.6/Co-product production will vary significantly based on feedstock used.
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
29
Table 1.7: Major Petrochemical Clusters in Canada, Summary
ALBERTA
From: Petrochemical Plants
Type
To: Derivative Plants
Feedstock
Req. (kt/yr)
Capacity (kt/yr)
Type
Olefins Plants
68%
20%
3%
91%
9%
2,790
806
121
3,717
380
Total
99%
99%
365
365
Balance
1%
Ethylene Crackers
4,097
Total
Balance
Aromatics Plants
Benzene
370
6
Polyethylene/ Similar Plants
MEG Plants
SM Plant
Total Derivative Plants
Excess Capacity
SM Plant
Total Derivative Plants
Gasoline Blend, Industrial
Chemicals, and Solvents
ONTARIO
From: Petrochemical Plants
Type
To: Derivative Plants
Feedstock
Req. (kt/yr)
Capacity (kt/yr)
Type
Olefins Plants
Ethylene Crackers
1,139
Total
Balance
Aromatics Plants
Benzene
340
88%
10%
98%
2%
Total
100%
100%
Balance
0%
Toluene
422
Total
Balance
100%
100%
0%
1,002
116
1,118
21
339
339
1
422
422
-
Polyethylene/ Similar Plants
SM Plant
Total Derivative Plants
Excess Capacity
SM Plant
Total Derivative Plants
Gasoline Blend, Industrial
Chemicals, and Solvents
Gasoline Blend, Industrial
Chemicals, and Solvents
Total Derivative Plants
QUEBEC
From: Petrochemical Plants
Type
To: Derivative Plants
Feedstock
Req. (kt/yr)
Capacity (kt/yr)
Type
Aromatics Plants
Benzene
350
Total
Balance
Toluene
240
Total
Balance
100%
350
100%
0%
350
-
100%
240
100%
0%
240
-
Benzene Derivatives (Including p-X
plant) & Refinery Feedstocks
Total Derivative Plants
Toluene Derivatives (Including p-X
plant) & Refinery Feedstocks
Total Derivative Plants
CANADA
From: Petrochemical Plants
Type
To: Derivative Plants
Feedstock
Req. (kt/yr)
Capacity (kt/yr)
Type
Olefins Plants
Ethylene Crackers
5,236
Total
Balance
Aromatics Plants
Benzene & Toluene
Plants
1,722
Total
Balance
72%
15%
5%
92%
8%
3,791
806
237
4,834
402
41%
41%
704
704
59%
1,018
Polyethylene/ Similar Plants
MEG Plants
SM Plants
Total Derivative Plants
Excess Capacity
SM Plants
Total Derivative Plants
Other Benzene & Toluene
Derivatives (Including p-X plant) &
Refinery Feedstocks
Source: CERI analysis, based on data from Table 1.6
May 2014
30
Canadian Energy Research Institute
Table 1.6 also provides information on facilities that produce various grades of polyethylene (PE)
and similar products (including ethylene-vinyl acetate (EVA) and linear-alpha olefins (LAO)
primarily) in Canada. Over 70 percent of this capacity is located in AB. These PE, EVA, and LAO
plants have the capacity to absorb close to 8.4 Blbs/yr (or about 3,791 kt/yr) of ethylene and
produce 8.4 Blbs or 3,817 kt/yr of plastics.
Other derivative plants, including mono-ethylene glycol (MEG) and styrene monomer (SM)
plants have the capacity to use an estimated 2.3 Blbs/yr (or 1,043 kt/yr) of ethylene as
feedstock and produce over 5 Blbs/yr (or 2,276 kt/yr) of products.
Thus, combined, PE, EVA, LAO, MEG, and SM plants have the capacity to absorb a total of close
to 10.7 Blbs/yr (or 4,834 kt/yr) of ethylene as a feedstock and produce about 12.5 Blbs/yr (or
6,093 kt/yr) of output. This implies that currently, in Canada as a whole, there is an ethylene
production capacity surplus of about 0.9 Blbs/yr (or 402 kt/yr). This surplus in turn translates
into a feedstock requirement of about 25 kb/d of NGLs/naphtha and makes the effective (or
derivative-based) demand for olefins petrochemical feedstock in Canada about 317 kb/d of
NGLs/naphtha. 74
Table 1.7 illustrates this point, and shows that the current ethylene production capacity surplus
situation is particular to AB. Thus, in order for ethylene cracking nameplate capacity to be fully
utilized in AB, not only should there be enough ethane feedstock supplied in the WCSB, but
derivative plant (or downstream) investments are required. These investments will in turn lead
to an increase in ethane use.
As will be further discussed, midstream investments are being made in order to increase
feedstock availability in AB partly stimulated by the Incremental Ethane Extraction Policy (IEEP).
Additionally, Nova Chemicals has announced the construction of a new PE reactor at its Joffre
complex and the possibility of ethylene capacity de-bottlenecks as an example of downstream
investments announced to monetize increasingly available NGLs in Canada.
In the Sarnia area,75 given the NGL feedstock capacity being developed through the Mariner
West and UTOPIA pipelines, which could potentially far exceed feedstock requirements for
ethylene crackers and derivative plants in the area, CERI believes that there is an opportunity to
expand both ethylene cracking and derivative plant capacity in the area.
In regards to aromatics plants, production capacity is mainly located in ON and QC. While
benzene production appears to be fully utilized in both AB and ON by the SM plants, benzene
production in QC must be allocated to other uses such as gasoline blending but can also feed
the para-xylene plant in Montreal.76
74
342 kb/d – 25 kb/d = 317 kb/d
Nova’s Corunna cracker has been re-tooled to maximize NGL use, thus limiting and eliminating C5+/heavy feeds
76
Dow Chemicals has a manufacturing site in Varennes, QC which produces STYROFOAM. While not much information is
available on this plant there is a possibility that some of the benzene around the Montreal area is used by this plant
75
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
31
Toluene production around Sarnia is assumed to be used internally by refineries, while some of
the toluene around Montreal is used at the para-xylene plant and the remainder internally.
Other petrochemical facilities in Canada include the Alberta EnviroFuels (AEF) facility in AB
which produces iso-octane from field butanes (f-butanes) for gasoline blending.
Meanwhile, the Williams Redwater fractionator in AB produces olefins from the processed offgas SGLs mix including ethylene, polymer-grade propylene (PGP), as well as butylene used as
alky-feed for gasoline.
In Sarnia, Lanxess uses butanes, butylene, butadiene, styrene, and other chemicals to produce
various grades of rubbers and other products. And, in Montreal, para-xylene (p-xylene) made
using benzene and toluene is used for the production of purified terephthalic acid (PTA), which
is in turn used to manufacture polyethylene terephthalate (PET) for plastic goods such as water
bottles.
Figure 1.13 provides a breakdown of petrochemical production in Canada from 2002 to 2012.
Figure 1.13: Canadian Petrochemical Production (kt/yr) (2002 - 2012) and
2012 % Share of Total
9,000
20,000
8,018
7,443 7,478
7,189
6,861
7,000
6,680 6,762 6,752
Butadiene [2901.24.10]
16,000
4%
6,134
Toluene [2902.3]
14,000
6,000
kt/yr
Butylene [2901.23]
18,000
7,497 7,607
12,000
5,000
10,000
4,000
8,000
3,000
MMlbs/yr
8,000
Xylene (Including PET Equivalent)
Benzene [2902.2]
6,000
Propylene, all grades [2901.22]
2,000
4,000
Ethylene (PE Based Estimate)
1,000
2,000
-
3% 3%
4%
8%
9%
69%
Total (kt/yr)
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
77
78
Source: Data from Industry Canada, Statistics Canada, and CERI estimates. Figures by CERI
The first apparent trend is that overall petrochemical production levels declined between 2002
and 2009 and have since recovered to stable levels around 6,800 kt/yr over the last few years
(2011-2012) in line with overall economic activity. By 2012, ethylene, propylene, benzene, and
xylenes (combined) accounted for 90 percent of petrochemical production in Canada.
77
Industry Canada, Industries and Business, Canadian Chemical Industry, Industry Profiles, Petrochemicals Industrial Profile:
http://www.ic.gc.ca/eic/site/chemicals-chimiques.nsf/eng/bt01135.html
78
Table 303-0053, Production of industrial chemicals and synthetic resins.
Table 303-0014, Production of industrial chemicals and synthetic resins.
Available at: http://www5.statcan.gc.ca/cansim/a33?RT=TABLE&themeID=512&spMode=tables&lang=eng
May 2014
32
Canadian Energy Research Institute
Since most petrochemicals are used to manufacture consumer goods, production is very much
driven by overall economic activity and growth, and thus, during the 2008/09 economic
downturn, overall production levels of petrochemicals in Canada was commensurate with lower
demand and sluggish economic activity in Canada. Meanwhile, a large portion of PE and other
derivatives are exported primarily to the US but also other markets, thus economic activity in
those markets affects demand and production levels for petrochemicals in Canada.
Given that a large portion of world petrochemical production capacity is based on crude derived
feedstock (such as naphtha),79 thus making them the marginal cost suppliers and the price
setters, commodity prices such as crude oil prices (as well as processing costs) are directly tied
to the price for petrochemical intermediates, derivatives, and consumer goods. As such,
demand and production levels adjust according to commodity price levels and cycles as well.
In 2008, Petromont decided to mothball its olefins and poly-olefins manufacturing facilities80 in
Montreal (for which the primary feedstock was naphtha and gas oil), thus taking off-line about
300 kt/yr (or 0.7 Blbs) from total ethylene capacity in Canada as well as associated co-products.
Compared to 2002 levels, production of all petrochemicals (except for ethylene) has fallen. In
absolute and percentage terms, production of propylene, benzene, and butylene have fallen the
most. CERI believes there are various factors behind this trend.
One factor is the closure of petrochemical facilities over the last decade in ON and QC, including
refineries and steam crackers. Closure of refineries leads to decreased levels of propylene and
benzene production, while closure of the Petromont facility, which used primarily heavy feeds,
not only reduced overall ethylene production but also co-product supply.
Furthermore, as gasoline production in Canada has decreased over the last decade (driven by
lower demand), given that a large portion of benzene is used for gasoline blending, demand for
benzene, and thus, production, has declined.81
Last but not least, CERI estimates that the largest share of petrochemical production in Canada
comes from steam crackers. Therefore, an increase in ethylene production and a decrease in coproduct production points to a shift to a lighter feedstock slate at the ethylene crackers (Figure
1.14, bottom).
This trend is expected to continue as the Sarnia steam crackers continue to shift to a lighter
feedstock slate, resulting in lower output volumes of co-products and possibly affecting coproduct derivative users’ operations.
79
This is discussed in more detail in Part IV of the NGLs Update
ICIS, Canada Petromont closure “a major loss”: http://www.icis.com/Articles/2008/02/13/9100564/canada-petromontclosure-a-major-loss.html
81
There is an 86% correlation between gasoline production and benzene production levels (2002 – 2012)
80
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
33
Figure 1.14: Total Petrochemical Production in Canada by Source (Top), and Estimated
Ethylene Production from Steam Crackers by Feedstock (Bottom) (kt/yr) (2002 - 2012)
9,000
8,000
8,143
7,460
7,594
7,519
7,729
7,187
7,076
7,000
6,826
6,827
6,875
6,251
kt/yr
6,000
5,000
4,000
3,000
Other
Propane
Total CERI Estimates
2,000
1,000
Refineries/ Aromatics Plants
Ethylene Crackers
StatsCan Based Totals
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
6,000
94%
5,106
4,602
4,992
5,054
4,691
4,681
4,595
4,428
4,596
4,740
4,756
90%
4,000
kt/yr
92%
88%
3,000
86%
%
5,000
2012
84%
2,000
Heavy Feeds
Butane
Ethane/ Propane Mix
Estimated Ethylene Production
Ethylene Cracking Capacity (kt/yr)
1,000
2002
2003
2004
2005
2006
Light Naphthas/ LPGs
Propane
Ethane
Reported Ethylene Production (StatsCAN)
Cracking Capacity Utilization (%)
2007
2008
2009
2010
2011
82%
80%
78%
2012
Source: CERI estimates with data from Industry Canada, and Statistics Canada. Figures by CERI
CERI estimates that in 2012 approximately 89 percent of the petrochemicals were produced by
steam crackers, 9 percent by refineries (aromatics plants), and 2 percent by other plants82
(Figure 1.14, top).
It can also be observed that ethylene cracking capacity utilization has improved over the last
few years (Figure 1.14, bottom), and if this trend is to continue, future expansions in ethylene
cracking capacity and derivative plants can be expected.
This concludes the discussion of Canadian midstream and downstream infrastructure around
NGLs. The following section will briefly discuss US NGL infrastructure, followed by an analysis of
midstream and downstream infrastructure investments in Canada that aim to make use and
monetize increasingly available NGLs
82
Primarily PGP and butylene from the Williams fractionator
May 2014
34
May 2014
Canadian Energy Research Institute
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
35
NGL Infrastructure and NGL End-Users
in the United States
Natural Gas Processing Plants
As previously discussed, natural gas processing plants are a crucial link between the production
of raw gas and the end-users. Processing plants remove impurities in the gas stream making it
pipeline quality and ready for the end-user. They also remove the valuable liquid components
entrained in the raw gas stream (NGLs) and send them on for further processing into products.
Based on data from the US Energy Information Administration (EIA) (as well as other data
sources, see Table 2.1), CERI estimates that in 2012 there were 539 active natural gas processing
plants in the lower 48 states. About half of these are located in the Gulf Coast region of PADD
III.83
Figure 2.1: Gas Processing Capacity in the United States (US) Lower 4884 (MMcf/d) (2012)
85
Source: EIA
The total capacity of all active plants is around 69 bcf/d, however not all plants are running at
total capacity, so actual gas processed was around 44 bcf/d in 2012, indicating an average
utilization rate of about 65 percent (see Table 2.1).
83
Energy Information Administration, Natural Gas Annual Respondent Query System (EIA-757 Data through 2012)
http://www.eia.gov/cfapps/ngqs/ngqs.cfm?f_report=RP9&f_sortby=&f_items=&f_year_start=&f_year_end=&f_show_compid=
&f_fullscreen
84
Excludes Alaska (three plants with about 10 bcf/d of processing capacity) and Hawaii (no plants/processing capacity)
85
EIA, Today in Energy, natural gas processing plant data now available, October 25, 2012.
http://www.eia.gov/todayinenergy/detail.cfm?id=8530
May 2014
36
Canadian Energy Research Institute
Table 2.1: Natural Gas Processing Plants, Number and Capacity by PADD (Top) and Top 50
Owners’ Capacity86 (Bottom) in the US Lower 48 (MMcf/d) (2012)
PADD
# of Plants Processing Capacity (MMcf/d) 2012 Throughput (MMcf/d) Utilization (%)
I - East Coast
31
2,530
882
35%
II - Midwest
114
11,582
7,184
62%
III - Gulf Coast
269
37,829
24,952
66%
IV - Rockies
101
15,736
10,769
68%
V - West Coast
24
927
581
63%
US Total
539
68,603
44,369
65%
Enterprise Gas Processing, LLC
DCP Midstream
Williams
Targa Resources
Enbridge, Inc.
Enterprise Hydrocarbons, LP
Oneok Field Services
ExxonMobil Production Company
BP America Production Company
Williams Production RMT / Williams…
Western Gas Partners, LP
Enogex Products LLC
DCP East Texas Gathering
Merit Energy Company
Energy Transfer
Targa Midstream Services, LLC
Enterprise Field Services, LLC
QEP Field Services
MarkWest Energy Partners LLC
National Helium
Devon Energy Corp
Regency Field Services LLC
Anadarko Petroleum Corp
Williams Field Services
Plains Gas Solutions, LLC
Enbridge Pipelines (Texas Gathering) L.P.
Enterpise Product Partners
Discovery Producer Services
ExxonMobil Corporation
ConocoPhillips
Enbridge G & P (East Texas) L.P.
The Williams Companies Inc.
Energy Transfer Equity, LP
Enbridge G & P
QEP Field Services Company
Williams Field Services-Gulf Coast Company…
Questar Pipeline Company
MarkWest Energy Appalacia, LLC
Devon Gas Services LP
Linn Energy
Occidental Permian Ltd
Oneok Rockies Midstream
Occidental of Elk Hills, Inc
DCP Southeast Texas Plants
Oxy
Pioneer Natural Resources
MarkWest Liberty Midstream & Resources
ConocoPhillips (Burlington Resources)
Crosstex Energy
-
PADD
PADD
PADD
PADD
PADD
1,000
2,000
3,000
I - East Coast
II - Midwest
III - Gulf Coast
IV - Rockies
V - West Coast
4,000
5,000
6,000
7,000
8,000
MMcf/d
87
88
89
90
91
Source: Argus, CERI research, EIA, Industry data, PennWell MAPSearch, Platts, and Oil & Gas Journal. Table by CERI
86
There were a total of 254 distinct gas processing plant owners in the US in 2012. The top 50 owners’ capacity accounted for
55.2 bcf/d of capacity or around 80 percent of the US lower 48 2012’s total
87
Argus: NGL Shale Gas Special Report:
https://media.argusmedia.com/~/media/Files/PDFs/LPG/Argus%20NGL%20Shale%20Gas%20Special%20Report.pdf
88
See footnotes 83 & 84.
Additionally: Energy Information Administration (EIA), Natural Gas Processing Plants in the United States: 2010 Update:
http://www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2010/ngpps2009/
89
In undertaking research on United States NGL infrastructure, CERI reviewed publicly available documents such as annual
information forms (AIFs), annual reports and presentations, as well as websites from various companies operating in the US
including Access Midstream, Anadarko Petroleum Corp., Blue Racer Midstream, Buckeye Partners, Caiman Energy, Crestwood,
DCP Midstream, Dominion Transmission, Enlink Midstream, Enterprise Products, Kinder Morgan, MarkWest Energy Partners,
NuStar Energy, Oneok Partners, Phillips 66, Sunoco Logistics, Targa Resources, and Williams amongst others. Additionally, RBAC
Inc. from Sherman Oaks, California and RBN Energy LLC from Houston, Texas provided data used as a means of cross-referencing
CERI’s research and as a further step in the due diligence process
90
Platts, Special Report, The North American Gas Value Chain: Developments and Opportunities:
http://china.platts.com/IM.Platts.Content/InsightAnalysis/IndustrySolutionPapers/GasValueChain.pdf
91
2013 Worldwide Gas Processing Survey and data from various articles from print editions
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
37
The number of natural gas processing plants has increased steadily over the last decade growing
from 451 in 2004 (earliest available data from the EIA) to 490 by 2009, and an estimated 539 by
year-end (YE) 2012.
Between 2004 (51.2 bcf/d of total capacity) and 2012, capacity increased by 34 percent (or by
over 17.4 bcf/d in net) with close to half of the total net growth coming from the Rockies area
(PADD IV: 8.3 bcf/d increase) as processing capacity across Wyoming, Colorado, and Utah
increased rapidly. The second largest growth region was the Lower or producing Midwest area
with rapid increases in processing capacity across Kansas and Oklahoma. This reflects the focus
of US gas producers in the earlier part of the decade on conventional gas and CBM development
in the Lower Midwest/Rockies region.
More recently and going forward, as US gas producers concentrate on shale gas development
and in particular wet or liquids-rich/oil prone shale plays, new processing capacity is expected
to be added primarily around PADDs III (Texas: Eagle Ford, Permian, Others), I (West Virginia and
Pennsylvania: Marcellus/Utica), and II (Ohio, Oklahoma, and North Dakota: Utica, Woodford,
and Bakken) as seen on Figure 2.2.
Figure 2.2: US Lower 48 Gas Processing Capacity Additions by Region (MMcf/d), 2011 - 2016
7,000
2011 - 16 Total US Additions: 15,178 MMcf/d
PADD III: 5,625 MMcf/d (39%)
PADD I: 5,560 MMcf/d (38%)
PADD II: 3,993 MMcf/d (23%)
6,000
5,000
Kentucky
Oklahoma
North Dakota
MMcf/d
Ohio
4,000
Pennsylvania
3,000
West Virginia
Texas
2,000
Total PADD II
Total PADD I
1,000
Total PADD III
2011
2012
2013
2014
2015
2016
Source: Argus, CERI research, EIA, Industry data, PennWell MAPSearch, Platts, and Oil & Gas Journal. Figure by CERI
CERI estimates that by 2016, gas processing capacity in the US lower 48 will increase to 80 bcf/d
(Figure 2.3).
CERI estimates indicate that by 201692 the single largest increase in processing capacity will
occur around the Marcellus/Utica region (West Virginia, Ohio, and Pennsylvania) reaching an
estimated 8.8 bcf/d of processing capacity by 2016 compared to 2.5 bcf/d in 2012 (Figure 2.4).
92
As of the time of writing, 2016 was the latest year for which projects have been announced. This applies to gas plants,
fractionators, and pipelines as presented in this section of the report
May 2014
38
Canadian Energy Research Institute
Figure 2.3: US Lower 48 Gas Processing Capacity by Region (MMcf/d), 2004-2016
MMcf/d
79,978
79,378
77,878
75,083
67,038
66,828
67,987
63,533
56,588
53,736
60,000
51,177
70,000
59,810
80,000
68,643
90,000
50,000
40,000
PADD V
PADD I
PADD II
PADD IV
PADD III
Total US
30,000
20,000
10,000
-
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Source: Argus, CERI research, EIA, Industry data, PennWell MAPSearch, Platts, and Oil & Gas Journal. Figure by CERI
Figure 2.4: Marcellus/Utica Gas Processing Capacity (MMcf/d), 2004-2016
10,000
9,000
8,000
MMcf/d
7,000
6,000
Ohio
8,365
8,765
Pennsylvania
6,965
West Virginia
5,845
Marcellus/ Utica
5,000
4,000
2,500
3,000
1,462
2,000
1,000
391
414
438
463
490
519
866
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Source: Argus, CERI research, EIA, Industry data, PennWell MAPSearch, Platts, and Oil & Gas Journal. Figure by CERI
Beyond 2016, gas processing capacity additions may be required around different regions of the
US based on the natural gas production outlook scenario (2013 to 2030 timeframe). This will be
further discussed in the outlook report (Part IV).
Fractionators
Once the NGLs are removed from the natural gas stream, this raw NGL mix is sent to a
fractionator to be split into individual products made to specification for a given end-user.
As of 2012, CERI estimates that the US had just over 3 million b/d (MMb/d) of total
fractionation capacity. Around 70 percent of the fractionation capacity is located in PADD III
(Gulf Coast) with a major hub around Mont Belvieu, Texas.
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
39
Meanwhile, the mid-Continent area (Kansas/Oklahoma) and the Conway, Kansas hub is a
secondary hub for NGLs, accounting for roughly 570 kb/d of fractionation capacity. Figure 2.5
shows US fractionation capacity by region.
Figure 2.5: US Fractionation Capacity by Region (Top) and by Operator (Bottom) (kb/d), 2012
2,500
80%
2,196
2012 Total US Capacity: 3,079 kb/d
70%
2,000
50%
kb/d
1,500
40%
1,000
30%
716
% of Total
60%
20%
500
122
10%
34
12
PADD IV - Rockies
PADD V- West
Coast
-
0%
PADD I - East
Coast
PADD II - Midwest
PADD III - Gulf
Coast
Enterprise Product Partners
Oneok
Cedar Bayou Fractionators (Targa)
Gulf Coast Fractionators (Conoco, Devon,…
Williams
ExxonMobil
LoneStar NGL
Chevron Phillips (CP) Chemical
Aux Sable
Targa Resources
MarkWest Liberty Midstream
Formosa Hydrocarbons Company
Copano Energy
Caiman Eastern Midstream
CrossTex Energy Services
DCP Midstream Partners
CMS Marysville Gas Liquids Co.
ConocoPhillips
MarkWest
Dominion Transmission
Plains All American (LPG Services)
SouthCross Energy
Kinder Morgan Energy Partners
Valero Energy
Energy Transfer Partners
Tembec Company
-
California
Utah
Colorado
West Virginia
Pennsylvania
Kentucky
Michigan
Illinois
Oklahoma
Kansas
New Mexico
Louisiana
Texas
PADD Total
% of Total
PADD I - East Coast
PADD II - Midwest
PADD III - Gulf Coast
PADD IV - Rockies
PADD I - West Coast
200
400
600
800
1,000
1,200
kb/d
Source: Argus, CERI research, EIA, Industry data, PennWell MAPSearch, Platts, and Oil & Gas Journal. Figure by CERI
Figure 2.6 illustrates some of the major fractionation additions that are planned, or newly
constructed in the US between 2011 and 2016 Most of the capacity growth will occur in Mont
Belvieu, TX. This is due to its proximity to both petrochemical facilities, and export facilities to
accommodate growing NGL exports. However, new fractionation capacity is also being added in
PADDs I and II reflecting the increased production coming from the Marcellus and Utica plays,
but also the evolving marketing options available to regional NGL producers. These include
access to local markets that were previously served by inflows from other areas (primarily
Canadian/overseas LPG imports and inter-PADD transfers), access to Canadian export markets
(diluent, heating, refining, and petrochemicals), as well as planned US East Coast and West
Coast NGL/LPG export facilities (further discussed in Part III).
May 2014
40
Canadian Energy Research Institute
Figure 2.6: Fractionation Capacity Additions by Area (Top) and Operator (Bottom) (kb/d),
2011 – 2016
1,000
2011 - 16 Total US Additions: 3,298 kb/d
PADD III: 2,295 kb/d (70%)
PADD I: 556 kb/d (17%)
PADD II: 448 kb/d (13%)
900
800
Ohio
North Dakota
Kansas
Illinois
600
West Virginia
kb/d
700
500
Pennsylvania
400
Texas
300
Louisiana
PADD II - Midwest
200
PADD I - East Coast
100
PADD III - Gulf Coast
2011
2012
2013
2014
2015
2016
Enterprise Product Partners
Cedar Bayou Fractionators (Targa)
MarkWest Liberty Midstream
Oneok
Phillips 66
Williams Energy/ BoardWalk JV
LoneStar NGL
Kinder Morgan/ Targa Resources JV
MarkWest Utica
CrossTex Energy Services
Blue Racer Midstream (Caiman/ Dominion)
LoneStar NGL/ Sunoco
Utica East Ohio Midstream (UEOM)
Occidental Petroleum (OxyChem)
Plains All American (Plains Gas Solutions)
Caiman Eastern Midstream (Williams Partners)
Formosa Hydrocarbons Company
Equistar Chemical (LyondellBasell)/ TexStar Midstream
Cheasepeake, M3 Midstream, EV Energy (UEOM)
Gulf Coast Fractionators
Caiman Eastern Midstream
Williams Partners (Ohio Valley Midstream)
MarkWest Liberty Partners
Hess Corporation
SouthCross Energy
Aux Sable
Chevron Phillips (CP) Chemical
Copano Energy
Energy Transfer Partners
PADD I - East Coast
PADD II - Midwest
PADD III - Gulf Coast
-
50
100
150
200
250
300
350
400
kb/d
Source: Argus, CERI research, EIA, Industry data, PennWell MAPSearch, Platts, and Oil & Gas Journal. Figure by CERI
CERI estimates that by 2016, fractionation capacity in the US will increase by 2.6 MMb/d or 86
percent compared to 2012 levels, to reach an estimated 5.7 MMb/d (Figure 2.7).
Around the Marcellus/Utica area (Ohio, Pennsylvania, and West Virginia), fractionation capacity
will increase rapidly from an estimated capacity of 122 kb/d in 2012 to close to 850 kb/d by
2016 (Figure 2.8). By then, about 43 percent of the 365 kb/d of regional fractionation capacity
additions will be de-ethanization capacity aimed at reaching US Gulf Coast and Midwest
petrochemical markets, but also Canadian and possibly overseas petrochemical markets. As this
situation develops, the Marcellus/Utica region will become an important NGL hub in North
America, yet the US Gulf Coast area will continue to dominate US NGL markets.
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
41
Figure 2.7: US Fractionation Capacity by Region (kb/d) (2009 – 2016)
5,625
6,000
California
Utah
Colorado
Pennsylvania
West Virginia
Kentucky
Michigan
North Dakota
Ohio
Illinois
Oklahoma
Kansas
New Mexico
Louisiana
Texas
PADD IV
PADD V
PADD I
PADD II
PADD III
Total US
6,000
5,035
5,000
5,000
4,430
3,942
kb/d
4,000
4,000
3,079
2,750
3,000
2,264
3,000
2,425
2,000
2,000
1,000
1,000
-
2009
2010
2011
2012
2013
2014
2015
2016
Source: Argus, CERI research, EIA, Industry data, PennWell MAPSearch, Platts, and Oil & Gas Journal. Figure by CERI
Figure 2.8: Marcellus/Utica Total Fractionation (Top) and De-ethanization (Bottom)
Capacity (kb/d) (2009 – 2016)
900
Ohio
Pennsylvania
West Virginia
Marcellus/ Utica De-C2 Capacity
Total Marcellus/ Utica Fractionation Capacity
800
700
808
848
620
kb/d
600
500
422
400
300
200
92
100
19
19
2009
2010
122
400
350
300
kb/d
250
200
2011
2012
2013
2014
MarkWest Utica-Cadiz (Harrison Co.) -Ohio-New De-C2
MarkWest Utica-Noble Co., Seneca Complex -Ohio-New De-C2
Williams Partners (Ohio Valley Midstream)-Oak Grove (Marshall) -West Virginia-New De-C2
MarkWest Liberty Midstream-Sherwood -West Virginia-New De-C2
MarkWest Liberty Midstream-Mobley -West Virginia-New De-C2
Caiman Eastern Midstream (Williams Partners)-Taylor (Marshall Co.) -West Virginia-New De-C2 (2)
Caiman Eastern Midstream (Williams Partners)-Fort Beeler, Cameron -West Virginia-New De-C2 (1)
MarkWest Liberty Midstream-Majorsville -West Virginia-De-C2 2
249
MarkWest Liberty Midstream-Majorsville -West Virginia-De-C2 1
MarkWest Utica-Bluestone, Butler Co. (Keystone) -Pennsylvania-De-C2
MarkWest Liberty Partners-Houston -Pennsylvania-De-C2
Marcellus/ Utica De-C2 Capacity
2015
2016
365
325
150
106
100
50
-
-
-
-
2009
2010
2011
2012
0
2013
2014
2015
2016
Source: Argus, CERI research, EIA, Industry data, PennWell MAPSearch, Platts, and Oil & Gas Journal. Figure by CERI
May 2014
42
Canadian Energy Research Institute
Pipelines and Other Transportion Infrastructure
While NGLs are versatile and can be transported by truck, rail, barge, ship and pipeline, most
NGLs are transported via pipeline. Several major systems move raw NGLs from gas processing
plants to fractionators and then move finished products from fractionators to market.
Liquids Transport Infrastructure
The NGL pipeline network in the United States is designed mainly to transport liquids from
producing regions to PADDs II and III due to the location of fractionation hubs in Conway, KS and
Mont Belvieu, TX, along with the concentration of petrochemical facilities in the Gulf Coast
region.
Figure 2.9 shows the major NGL pipeline corridors and fractionation hubs in the United States
(see Appendices section for more detailed maps).
Just as gas processing capacity and fractionation capacity in the US has grown in recent years
(and is forecast to continue on this trend), NGL pipelines are being built and expanded to
accommodate new NGL production from NGL-rich shale gas production.
Some of the pipelines are being built to transport spec-grade (mostly ethane) NGLs to the Gulf
Coast, or for export markets (mostly to Canada). Pipelines are also being re-purposed in order to
export diluent (pentanes plus/naphtha/condensate) from various regions across the US to the
growing oil sands diluent market in Alberta. Y-grade (or raw NGL mix) pipelines are connecting
new producing regions to PADDs II and III for fractionation.
The majority of the new construction is occurring around the Marcellus and Utica shale in PADD
I and the Bakken in PADDs II and IV.
There is also significant NGL pipeline construction connecting the Eagle Ford and West Texas
shale plays in Texas to facilities on the Gulf Coast. Table 2.2 lists the existing and planned major
pipeline systems that transport NGLs across the US.
The first portion of Table 2.2 displays NGL mix or gathering systems (green arrows in Figure 2.8)
which serve to transport NGL mixes from gas plants or supply regions to fractionation or
processing hubs across PADDs (inter-PADDs) and within PADDs (intra-PADD).
The second portion of the table displays NGL or spec product distribution pipelines (blue arrows
on Figure 2.9).
These pipelines serve the purpose of delivering spec NGLs such as ethane, propane, butanes,
and pentanes plus from fractionation hubs to various markets. The end-users in those markets
may include residential, commercial, and industrial consumers such as petrochemical facilities,
and crude oil refineries, amongst others.
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
43
Figure 2.9: Major NGL Pipeline Corridors and Fractionation Centers in the United States
Bakken NGL
East System
SARNIA
CHICAGO
Buckeye System
Unity
Cornerstone
Mariner East
HOUSTON
CONWAY
NGL HUB
Existing NGL Mix Pipeline
Existing Spec NGL Pipeline
Proposed NGL Mix Pipeline
Proposed Spec NGL
Emerging Hub
MT. BELVIEU
93
Source: Background image from EIA, figure by CERI
93
EIA, Geography, Maps, US Energy Mapping System: http://www.eia.gov/state/maps.cfm
May 2014
44
Canadian Energy Research Institute
Table 2.2: US NGL Pipelines
Flow
PADDs I/II --> III
System
Bluegrass
Origin
Pennsylvania, West Virginia, Ohio
PADDs I/II --> III
Utica Marcellus Texas
Pipeline (UMTP)
Pennsylvania, West Virginia, Ohio
Subtotal PADDs I/II --> III*
NGL Mix Pipelines
INTER-PADD SYSTEMS
Destination Region
Lake Charles, Louisiana (Moss Lake)
Mt. Belvieu, Texas
Capacity (kb/d) Expansion (kb/d) Total Capacity (kb/d) Expected Completion
200
200
2016
200
-
US Gulf Coast (USGC)
200
Owners
Boardwalk/ Williams JV
2016
Kinder Morgan/MarkWest Energy
Partners (MarkWest and Energy
Minerals Group JV)
400
PADD II --> III
Arbuckle
Southern Oklahoma
Mt. Belvieu, Texas
180
60
240
2012
Oneok Partners
PADD II --> III
Sterling III
Medford, Northern Oklahoma
Mt. Belvieu, Texas
193
-
193
2013
Oneok Partners
PADD II --> III
Sterling II
Conway, Kansas
Mt. Belvieu, Texas
150
-
150
Operating
Oneok Partners
PADD II --> III
Sterling I
Conway, Kansas
Mt. Belvieu, Texas
150
-
150
Operating
Oneok Partners
PADD II --> III
Southern Hills
Kansas/Oklahoma
Mt. Belvieu, Texas
175
-
175
2013
DCP Midstream (Phillips 66/ Spectra
Energy)
PADD II --> III
Mid-America Pipeline (MAPL)
System: Conway South
Segment
Conway, Kansas
Hobbs, New Mexico/ Texas border
75
-
75
Operating
Enterprise Product Partners
DCP Midstream Partners/Anadarko
Petroleum Corp./Enterprise Product
Partners JV
Subtotal PADD II --> III
USGC
983
PADD IV --> III
Front Range
DJ Basin, Colorado (Weld County)
Skelly Town, Texas
150
-
150
2014
PADD IV --> III
MAPL System: Rocky
Mountain Segment (RMGS)
Rocky Mountain overthrust/San Juan
Basin
PADD III (Hobbs: New Mexico/ Texas border)
275
85
360
2014
Enterprise Product Partners
Operating
Phillips 66/Chevron Phillips (CP)
Chemicals
PADD IV --> III
Powder River/Mextex
Sage Creek, Wyoming/Artersia, NM
Borger, Texas/Benedum Texas
70
-
70
Subtotal PADD IV --> III
USGC
580
TOTAL PADDs I, II, & IV --> III
USGC
1,963
PADD IV --> II
Overland Pass
PADD IV --> II
Subtotal PADD IV --> II
Wattenberg
(Opal) Wyoming (Greater Green River
Basin), Colorado (DJ Basin, Piceance)
DJ Basin
Flow
System
Origin
PADD II
Chrisholm
Kingfisher, Oklahoma
Conway, Kansas
42
-
42
Operating
PADD III
Sand Hills
Eagle Ford (SE Texas)/ Permian (W
Texas)
Mt. Belvieu, Texas
200
-
200
2013
DCP Midstream (Phillips 66/ Spectra
Energy)
PADD III
Texas Express Pipeline
Skellytown (Carson Co.)
Mt. Belvieu, Texas
280
-
280
2013
DCP Midstream Partners/ Enbridge
Energy Partners/ Anadarko Petroleum
Corp./Enterprise Product Partners JV
PADD III
Black Lake
NW Louisiana/ SE Texas
-
40
Operating
DCP Midstream
Seabreeze/Wilbreeze
SE Texas (Eagle Ford)
Mt. Belvieu, Texas
Seabreeze --> Wilbreeze --> Sand Hills --> Mt.
Belvieu, Texas
40
PADD III
50
-
50
Operating
DCP Midstream
PADD III
Seminole Pipeline
MAPL system: RMGS (Rockies) and
Conway South (Midwest) Segment/
Permian basin (West Texas)
Mt. Belvieu, Texas
260
-
260
Operating
Enterprise Product Partners
PADD III
Chaparral NGL
West Texas/New Mexico
Mt. Belvieu, Texas
125
-
125
Operating
Enterprise Product Partners
PADD III
Skelly-Belvieu
Skellytown (Carson Co.)
Mt. Belvieu, Texas
29
-
29
Operating
Enterprise Product Partners/Phillips 66
PADD III
West Texas Gateway
Permian/Delaware/Eagle Ford Basins
Mt. Belvieu, Texas
209
-
209
2012
LoneStar NGL LLC (Energy Transfer
Partners LP/Regency Energy Partners
LP)
PADD III
Eagle Ford/ Yoakum NGL
Pipeline
Eagle Ford Basin
Mt. Belvieu, Texas
310
140
450
2013
Enterprise Product Partners
PADD III
Cajun-Sibon
Louisiana
Mt. Belvieu, Texas
70
-
70
2013
Crosstex Energy LP
PADD III
PADD III
PADD III
TX Panhandle Y1/Y2
Line EZ
Sweeney EP
Sherman, Texas
Rankin, Texas
Mt. Belvieu, Texas
Borger, Texas
Sweeney, Texas
Sweeney, Texas
73
101
40
-
73
101
40
Operating
Operating
Operating
PADD III
West Texas LPG NGL Line
New Mexico/Texas
Mt. Belvieu, Texas
245
-
245
Operating
Phillips 66
Phillips 66
Phillips 66/CP Chemicals
Atlas Pipeline/ Chevron Pipeline
Company
PADD III
West Texas System
West Texas (Permian/Barnett Basins)
Mt. Belvieu, Texas
140
-
140
Operating
PADD III
Justice System
260
80
340
2013
LoneStar NGL LLC
Mariner South
West Texas (Permian/Barnnet)/SE Texas
(Eagle Ford Basin)
Mt. Belvieu, Texas
Mt. Belvieu, Texas
PADD III
Subtotal PADD III
Nederland, Texas
US Gulf Coast
200
-
200
2,643
2015
LoneStar NGL LLC/Sunoco Logistics JV
PADD IV
Bakken NGL
Bakken play (Montana/ North Dakota)
Colorado (Overland Pass System)
60
135
2014
Oneok Partners
May 2014
PADD II (Bushton-Conway, Kansas)
195
PADD II (Bushton-Conway, Kansas)
Conway, Kansas
25
60
255
2013
Oneok Partners/ Williams JV
-
25
280
Operating
DCP Midstream
MAJOR INTRA-PADD SYSTEMS
Destination Region
Capacity (kb/d) Expansion (kb/d) Total Capacity (kb/d) Expected Completion
75
Owners
DCP Midstream (Phillips 66/ Spectra
Energy)
LoneStar NGL LLC
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
SPEC PRODUCT PIPELINES
ETHANE/PROPANE
Destination Region
45
Flow
System
Origin
PADDs I/II --> III
Applachia-to-Texas-Express
(ATEX)
Pennsylvania, West Virginia, Ohio
Mont Belvieu, Texas
125
PADDs I/II --> Ontario
Mariner West
Pennsylvania, West Virginia, Ohio
Sarnia, Ontario
50
PADDs I/II --> Export Terminal
Mariner East I
Pennsylvania, West Virginia, Ohio
Marcus Hook, Pennsylvania
PADDs I/II --> Export Terminal
Mariner East II
Pennsylvania, West Virginia, Ohio
Marcus Hook, Pennsylvania
PADDs I/II --> Ontario
Utica-to-Ontario-Pipeline
Access (UTOPIA)
Pennsylvania, West Virginia, Ohio
PADD II --> Alberta
Vantage
PADD II
MAPL: Conway North
Segment
PADD II
PADD III
MAPL: Ethane-Propane (E/P)
Mix Segment
AEGIS
Capacity (kb/d) Expansion (kb/d)
Expected Completion
Owners
190
2014
Enterprise Product Partners
-
50
2014
Sunoco Logistics/ MarkWest Liberty
Midstream & Resources, LLC JV
(MarkWest Energy Partners/Energy &
Minerals Group)
70
-
70
2014
70
-
70
2016
Sarnia, Ontario
50
-
50
2017
Kinder Morgan
North Dakota
Alberta/Saskatchewan Empress border:
connection to Alberta Ethane Gathering System
(AEGS)
40
-
40
2014
Mistral Midstream
Conway, Kansas
Upper Midwest (Chicago area)
80
-
80
Operating
Enterprise Product Partners
65
Total Capacity (kb/d)
Sunoco Logistics/ MarkWest Liberty
Midstream & Resources, LLC JV
Sunoco Logistics/ MarkWest Liberty
Midstream & Resources, LLC JV
Conway, Kansas
Petrochemical plants in Iowa and Illinois
70
-
70
Operating
Enterprise Product Partners
Mt. Belvieu, Texas
Petrochemical plants along the USGC (TX-LA)
425
-
425
2014
Enterprise Product Partners
PADD III --> II
Blue Line
Borger, TX
PADD III --> I
Dixie
Mt. Belvieu/ South Louisiana/
Mississippi
PADD III --> II & I
TEPPCO/ Centennial
Upper Texas Gulf Coast/Beaumont,
Texas
PADD II
North System
PADD II
East System
PADD II
PADD II
PADD III
Conway to Wichita
Medford
Sweeney Propane/Butane
Kansas <--> Illinois
Kansas NGL hub (Conway) & Area
Refineries
Conway, Kansas
Ponca City, Oklahoma
Clemens, Texas
LPG: PROPANE/BUTANES
Upper Midwest (St. Louis, ILL)
Southeastern US (Alabama, Georgia, Louisiana,
Mississippi, North Carolina, South Carolina, and
Texas)
TEPPCO: Texas --> Seymour, Indiana --> Chicago,
Illinois/Lima, Ohio/Selkirk, New
York/Philadelphia, Pennsylvania. Centennial:
Bourbon, Illinois
Kansas <--> Illinois
Iowa, Kansas, Nebraska, North Dakota, South
Dakota
Whichita, Kansas
Medford, Oklahoma
Pasadena, Texas
29
-
29
Operating
Phillips 66
160
-
160
Operating
Enterprise Product Partners
100
-
100
Operating
Enterprise Product Partners
134
-
134
Operating
Oneok Partners
100
-
150
Operating
NuStar Energy LP
38
60
31
-
38
60
31
Operating
Operating
Operating
Phillips 66
Phillips 66
Phillips 66/CP Chemicals
DILUENT: NATURAL GASOLINE/NAPHTHA/CONDENSATE
PADD I/II --> II
Unity Pipeline
Kensigton, Ohio
Griffth, Indiana (Explorer pipeline)
60
-
60
2015
Harvest Pipeline Company/NiSouce
Midstream Services LLC/Somerset Gas
Transmission Company, LLC JV
PADD I/II --> II
Cornerstone
Cadiz, Ohio
Marathon's Canton, Ohio Refinery
40
-
40
2016
MPLX (Marathon Petroleum Energy
Logistics)
PADD III --> II
Explorer
Houston/Port Arthur Texas
Upper Midwest (Chicago area)
350
-
350
Operating
Explorer Pipeline Consortium
PADD III --> II
Capline
Louisiana
Upper Midwest (Chicago area)
1,000
-
1,000
Operating
Plains Midstream/Marathon
Petroleum/ Others
PADD III --> II
TEPPCO
Upper Texas Gulf Coast/Beaumont,
Texas
500
-
500
Operating
Enterprise Product Partners
PADD II --> AB
Southern Lights
Manhattan, Illinois
TEPPCO: Texas --> Seymour, Indiana --> Chicago,
Illinois/Lima, Ohio/Selkirk, New
York/Philadelphia, Pennsylvania. Centennial:
Bourbon, Illinois
Edmonton, Alberta
180
95
275
2015
Enbridge
PADD II --> AB
Cochin
Kanakee Co., Illinois
Fort Saskatchewan, Alberta
95
2014
Kinder Morgan
95
-
* Other Marcellus/Utica NGL takeaway project proposals that have been previously announced but CERI believes are not likey to materialize include Spectra/El Paso's 60 kb/d Marcellus Ethane Pipeline (MEP) from the region to the US Gulf Coast (El Paso Corp. was acquired by
Kinder Morgan in 2012); Cumberland Palteau Pipeline Co. LLC's 75-125 kb/d ethane pipeline to Baton Rouge, Louisiana; NOVA Chemicals/Buckeye's Union NGL Pipeline project to Sarnia, Ontario, and; Enbridge's Marcellus to US Upper Midwest NGL pipeline to Aux Sable's facilities
in Channahon, Illinois. Most of these proposals were brought up around 2010-11 and little information has been provided since. Furthermore, given the more recently announced and under construction projects in the area, it is possible that more than enough takeaway capacity
will be build over the coming years, depending on the NGL outlook
Source: Argus, CERI research, EIA, Industry data, PennWell MAPSearch, Platts, and Oil & Gas Journal. Figure by CERI
Petrochemical Facilities
As of 2012, there were 38 ethylene cracking facilities in the US with total capacity to produce
close to 30 million tonnes of ethylene per year.
About 96 percent of the production capacity is located in the US Gulf Coast region, primarily in
Texas (71 percent of total US capacity) but also Louisiana (24 percent). The remaining four
percent of ethylene production capacity is located primarily in the upper Midwest.
There were 16 major companies producing ethylene in the US in 2012, with no company owning
more than 20 percent of total capacity. CERI estimates that the US ethylene crackers have the
ability to use a maximum of close to 2 MMb/d of NGLs/naphtha, with the majority of capacity
able to use ethane as the primary feedstock (Table 2.3).
May 2014
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Canadian Energy Research Institute
Table 2.3: US Ethylene Cracking Capacity by Region/Company (kt/yr) and Estimated Feedstock
Requirements (kb/d), 2012
Location
PADD III - Gulf Coast
Texas
Port Arthur, TX
Chocolate Bayou, TX
Baytown, TX
Capacity
(kt/yr)
26,782
19,923
2,350
2,296
2,197
% of Total
96%
71%
8%
8%
8%
Company
Capacity
% of Total
(kt/yr)
4,880
17%
4,090
15%
3,900
14%
3,555
13%
2,630
9%
Sweeny, TX
1,865
7%
Equistar Chemicals LP (LyondellBasell)
ExxonMobil Chemicals Co.
Dow Chemical Co.
Chevron Phillips Chemical Co. LP
Shell Chemicals Corp.
Channelview, TX
1,750
6%
INEOS Olefins and Polymers USA
1,752
6%
Freeport, TX
1,640
6%
Formosa Plastics Corp. USA
1,541
6%
Westlake Petrochemicals Corp.
1,293
5%
BASF Fina Petrochemicals
Eastman Chemical Co.
DuPont
Flint Hills Corp.
Williams Olefins
Sasol North America Inc.
Hunstman Corp.
Javelina Co.
Total
860
781
680
635
612
472
180
151
28,012
3%
3%
2%
2%
2%
2%
1%
1%
100%
Point Comfort, TX
Deer Park, TX
Corpus Christi, TX
Cedar Bayou, TX
Beaumont, TX
LaPorte, TX
Longview, TX
Orange, TX
Port Neches, TX
Houston, TX
Louisiana
Lake Charles, LA
Norco, LA
Plaquemine, LA
Taft, LA
Baton Rouge, LA
Geismar, LA
PADD II - Midwest
Illinois
Morris, ILL
Iowa
Clinton, IO
Kentucky
Calvert City, KY
US Total
1,541
1,179
922
835
816
789
781
680
180
102
6,859
1,561
1,451
1,260
1,000
975
612
1,230
550
550
476
476
204
204
28,012
6%
4%
3%
3%
3%
3%
3%
2%
1%
0%
24%
6%
5%
4%
4%
3%
2%
4%
2%
2%
2%
2%
1%
1%
100%
Feedstock Capacity
Ethane
Propane
Butane
Naphtha
Gas Oil
Other
Total
kb/d % of Total
1,061
54%
391
20%
73
4%
317
16%
80
4%
56
3%
1,977 100%
Source: Argus, CERI research, EIA, Industry data, PennWell MAPSearch, Platts, and Oil & Gas Journal. Figure by CERI
The US petrochemical industry is currently experiencing a renaissance.
With growing production of NGLs from liquids-rich shale gas, ethane and propane are oversupplying demand in the US and driving down the price for ethane and propane as a
petrochemical feedstock. Consequently, existing facilities are being expanded or re-tooled to
take advantage of discounted feedstock, while new petrochemical facilities are being built and
proposed, largely in the Gulf Coast region, with some proposals surrounding Marcellus and
Utica shale production in PADD I.
Table 2.4 outlines petrochemical expansions and new constructions.
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
47
Table 2.4: US Petrochemical Facility Expansions and New Constructions
Company
Plant
Type
Dow Chemical Co.
Westlake Petrochemicals Corp.
BASF Fina Petrochemicals
Williams Olefins
INEOS Olefins and Polymers USA
Taft 2, LA (Hahnville)
Lake Charles #1, LA
Port Arthur, TX
Geismar, LA
Chocolate Bayou, TX
Re-start
Expansion
Revamp/ Expansion
Expansion
Expansion
Westlake Petrochemicals Corp.
Calvert City, KY
Equistar Chemicals LP (LyondellBasell)
2012
2013
2014
2015
2016
2017
2018
2019
2020
410
-
110
344
-
86
272
115
110
-
-
-
-
-
-
Feedstock Conversion (C3 --> C2) & Expansion
-
-
286
-
-
-
-
-
-
LaPorte, TX
Expansion
-
-
375
-
-
-
-
-
-
Dow Chemical Co.
Plaquemine (LHC 3), LA
Feedstock Conversion (C4/C5 --> C2)
-
-
222
-
-
-
-
-
-
Dow Chemical Co.
Chevron Phillips Chemical Co. LP
Equistar Chemicals LP (LyondellBasell)
Equistar Chemicals LP (LyondellBasell)
ExxonMobil Chemicals Co.
Chevron Phillips Chemical Co. LP
Dow Chemical Co.
Formosa Plastics Corp. USA
Sasol North America Inc.
OxyChem/MexiChem
Shell Chemicals Corp.
Aither Chemicals
Axiall Corp./Lotte Chemical
Braskem/Odebrecht (ASCENT)
Indorama Ventures Ltd.
Total New Capacity (kt/yr)
Required Ethane Feedstock (kb/d)
Freeport (LHC 7), TX
Sweeny, TX
Channelview, TX
Corpus Christi, TX
Baytown, TX
Cedar Bayou, TX
Freeport (LHC 9), TX
Point Comfort, TX
Lake Charles, LA
Ingleside, TX
Monaca, PA
Marcellus/Utica
Lousiana
Parkersburg, WV
US Gulf Coast
Expansion
Expansion
Expansion
Expansion
New Build (Brownfield)
New Build (Brownfield)
New Build (Brownfield)
New Build (Brownfield)
New Build (Brownfield)
New Build (Greenfield)
New Build (Greenfield)
New Build (Greenfield)
New Build (Greenfield)
New Build (Greenfield)
New Build (Greenfield)
410
26
454
28
278
91
1,724
107
113
363
586
37
1,500
1,500
93
1,500
1,500
900
3,900
243
1,500
555
2,055
128
1,500
300
1,000
2,800
174
1,500
1,500
3,000
187
94
95
Source: Argus, CERI research, EIA, ICIS, Industry data, PennWell MAPSearch, Platts, and Oil & Gas Journal. Figure by CERI
94
ICIS, US Gulf Coast cracker projects move forward: http://www.icis.com/resources/news/2013/07/22/9689733/us-gulf-coast-cracker-projects-move-forward/
ICIS, New Projects may raise US ethylene capacity by 52%, PE by 47%: http://www.icis.com/resources/news/2014/01/16/9744545/new-projects-may-raise-us-ethylene-capacityby-52-pe-by-47-/
95
Platts, Special Report: Petrochemicals: Time to get cracking: http://www.platts.com/IM.Platts.Content/InsightAnalysis/IndustrySolutionPapers/SR_Ethylene_AFPM_2013.pdf
May 2014
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Canadian Energy Research Institute
The expansions, repurposing, and new projects have the capacity to increase ethane demand by
close to 1 MMb/d between 2012 and 2020 and expand production capacity by over 16 million
tonnes/yr (MMt/yr) or close to 60 percent compared to 2012’s levels.
In addition to the projects listed above, four other world-scale ethylene crackers (around 1.5
MMt/yr each) have been discussed by companies such as Hanwha Chemical (Korea),
LyondellBasell, PTT Global Chemical, and Saudi Basic Industries Corp. (SABIC). If these were to
materialize, US ethylene production capacity could increase by another 6 MMt/yr. Additionally,
if these crackers were to target ethane as their primary feedstock, ethane demand could reach a
level of between 2 – 2.5 MMb/d of demand beyond 2020. Whether that much ethane is
possible to be produced in the US will depend on the different NGL outlook scenarios, but the
potential is without question, very large.
Prior to the shale gas boom, US oil and gas supplies were typically located in accessible areas
that were tied to existing gathering and processing infrastructure. Now and going forward, high
capital investments are required to connect newfound resources with processing plants,
fractionators, refineries, and petrochemical facilities. The midstream sector will need to evolve
and grow quickly in order to manage and capitalize on the NGL growth. If it does not respond
quickly enough it will constrain NGL production growth.
This concludes the brief discussion on NGL infrastructure in the US. The next section will focus
on investments in Canadian infrastructure to monetize increasingly available NGL volumes.
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
49
Analysis: Infrastructure Investments in
Canada to Connect NGL Supply and
Demand
The previous report’s analysis discussed how physical changes and economics in North
American natural gas markets are changing the way WCSB gas producers operate. A persistent
low gas price environment and evolving market fundamentals have led to a constant need to
improve profitability through cost competitiveness and revenue maximization.
But maximizing NGL revenue requires various pieces of midstream infrastructure to be in place
in order to take NGLs to market. Thus, the role of midstream infrastructure and midstream
companies is to connect supplies with end-use markets. Meanwhile, downstream infrastructure
needs to be sufficient and in place in order to either absorb or re-deploy NGL supplies. Thus, as
NGL supplies increase, demand and export infrastructure is also expected to expand.
This feature will discuss the main midstream infrastructure players in Western Canada, as well
as discuss trends in midstream infrastructure investments, while quantifying some of those
ongoing investments. Last but not least, downstream investments will be discussed leading into
Part III of the NGL update that will focus on NGL market fundamentals and economics.
Major Midstream Players in Western Canada
Figure 3.1 illustrates the largest natural gas producers (top left) and processors (top right), as
well as the largest NGL producers in AB for 2012 (bottom).
Starting with the top left chart, it can be observed that the top 15 companies produced under
two-thirds of total gas volumes in AB, while the other (467) operators accounted for just over
one-third of output. Thus, there are a few large producers but several small companies
producing gas in AB.
The top right chart illustrates a similar trend in regards to field processing, but it can be
observed that there are a lot fewer companies processing gas at the field level (125) than
producing gas (482). This is the case as gas processors benefit from economies of scale through
aggregation of produced volumes from several well sites towards a centralized processing
facility. The other interesting feature of the top right chart is that within the largest field gas
processors, there are a few third-party midstream companies. These companies do not own
production assets but rather offer various midstream services including gas gathering,
compression, and processing, as well as NGL extraction, fractionation, transportation and
storage (marketing). These companies are highlighted in bold on Figure 3.1.
May 2014
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Canadian Energy Research Institute
Figure 3.1: Top Natural Gas/NGL Players in AB: Natural Gas Production and Field Processing (top), NGLs Extraction (bottom)
(2012)*
CANADIAN NATURAL RESOURCES LIMITED
DEVON CANADA
9%
9%
HUSKY OIL OPERATIONS LIMITED
6%
SHELL CANADA ENERGY
6%
38%
9%
29%
CONOCOPHILLIPS CANADA (BRC) PARTNERSHIP
CENOVUS ENERGY INC.
8%
ENCANA CORPORATION
5%
APACHE CANADA LTD.
5%
PENN WEST PETROLEUM LTD.
5%
2%
2%
2% 3%
BONAVISTA ENERGY CORPORATION
5%
3% 3% 3%
6%
3%
SUNCOR ENERGY RESOURCES PARTNERSHIP
3%
7%
2%
2%
3%
3%
TAQA NORTH LTD.
5%
3%
4% 4% 4%
NISKA GAS STORAGE CANADA ULC
PEYTO EXPLORATION & DEVELOPMENT CORP.
Top 15 = 7,550 MMcf/d (62% of Total)
Other (467) = 4,713 MMcf/d (38%)
Total (482) = 12,263 MMcf/d
Top 15 = 7,361 MMcf/d (71% of Total)
Other (100) = 2,945 MMcf/d (29%)
Total (115) = 10,306 MMcf/d
PENGROWTH ENERGY CORPORATION
Other (467)
Keyera Energy Ltd.
Inter Pipeline Extraction Ltd.
AltaGas Ltd.
10%
1%
1%
1%
1%
1%
2%
3%
Devon Canada
18%
Keyera Energy Ltd.
9%
7%
Pembina NGL Corporation
15%
Plains Midstream Canada ULC
Inter Pipeline Extraction Ltd.
Dow Chemical Canada ULC
Plains Midstream Canada ULC
2%
7%
Husky Oil Operations Limited
3%
9%
3%
13%
1195714 Alberta Ltd.
1195714 Alberta Ltd.
8%
Shell Canada Energy
Pengrowth Energy Corporation
4%
8%
4%
7%
4%
5%
5%
6%
Canadian Natural Resources Limited
11%
9%
SemCAMS ULC
ATCO Midstream Ltd.
10%
11%
Talisman Energy Inc.
NGLs Mix
Penn West Petroleum Ltd.
Canadian Natural Resources Limited
ATCO Midstream Ltd.
Husky Oil Operations Limited
Suncor Energy Resources Partnership
Shell Canada Energy
Top 15 = 202 kb/d (82% of Total)
Other (87) = 45 kb/d (18%)
Total (102) = 247 kb/d
Spectra Energy Empress Management Inc.
AltaGas Ltd.
ConocoPhillips Canada (BRC) Partnership
3%
Keyera Energy Ltd.
Devon Canada
Canadian Natural Resources Limited
ConocoPhillips Canada (BRC) Partnership
Shell Canada Energy
Husky Oil Operations Limited
SemCAMS ULC
Encana Corporation
AltaGas Ltd.
Talisman Energy Inc.
Suncor Energy Resources Partnership
Peyto Exploration & Development Corp.
Pembina Gas Services Ltd.
Apache Canada Ltd.
Cenovus Energy Inc.
Other (100)
SemCAMS ULC
Spec NGLs
Top 15 = 425 kb/d (93% of Total)
Other (87) = 30 kb/d (7%)
Total (107) = 455 kb/d
ConocoPhillips Canada (BRC) Partnership
Other (87)
Source: Data from AER, analysis and figures by CERI
*See Table 1.2 for details on the ownership breakdown for 1195714 Alberta and Spectra Energy Empress Management Inc. Taylor Processing and Altagas have been summed
under Altagas’ name
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
51
CERI estimates that in 2012, these midstream companies accounted for about 30 percent of the
gas processed in AB at the field level, and the vast majority of the gas reprocessed at the
straddle plants.
In regards to companies extracting both NGL mixes and spec NGLs (Figure 3.1, bottom charts),
this space is largely dominated by midstream companies, thus the further downstream on the
midstream value chain, the more assets are owned by third-party midstream companies. CERI
estimates that in 2012, midstream companies accounted for 60 percent of the NGL mixes
extracted and 87 percent of the spec NGLs produced in AB.
Figure 3.2 displays the top processors and NGL extraction players in BC for 2012.
Figure 3.2: Top Natural Gas Processing (Top)/NGL Extraction Players (Bottom) in BC (2012)96
11%% 4%
1%
1%
2%
3%
4%
4%
42%
5%
5%
6%
6%
6%
8%
Top 15 = 3,627 MMcf/d (96% of Total)
Other (16) = 147 MMcf/d (4%)
Total (31) = 3,773 MMcf/d
%1%
11%0%
1%
2%2%
2%
2%
3%
3%
6%
52%
8%
8%
10%
Top 15 = 48 kb/d (99% of Total)
Other (10) = 1 kb/d (1%)
Total (25) = 49 kb/d
WESTCOAST TRANSMISSION COMPANY LIMITED
SPECTRA ENERGY MIDSTREAM CORPORATION
VERESEN ENERGY INFRASTRUCTURE INC.
SHELL CANADA LIMITED
MURPHY OIL COMPANY LTD.
CONOCOPHILLIPS CANADA OPERATIONS LTD.
CANADIAN NATURAL RESOURCES LIMITED
ENCANA CORPORATION
ARC RESOURCES LTD.
TALISMAN ENERGY INC.
TOURMALINE OIL CORP.
PENN WEST PETROLEUM LTD.
KEYERA ENERGY LTD.
AUX SABLE CANADA LTD.
ALTAGAS LTD.
Other (16)
ALTAGAS HOLDINGS INC.
WESTCOAST TRANSMISSION COMPANY LIMITED
SPECTRA ENERGY MIDSTREAM CORPORATION
CONOCOPHILLIPS CANADA OPERATIONS LTD.
CANADIAN NATURAL RESOURCES LIMITED
ARC RESOURCES LTD.
TOURMALINE OIL CORP.
CANBRIAM ENERGY INC.
SHELL CANADA LIMITED
AUX SABLE CANADA LTD.
KEYERA ENERGY LTD.
Husky Energy
VERESEN ENERGY INFRASTRUCTURE INC.
Imperial Oil
NuVista Energy
Source: Data from BCMNGD, analysis and figures by CERI
96
West Coast Transmission Company Limited and Spectra Energy Midstream Corporation are owned by the same entity. Veresen
Energy Infrastructure Inc. and Aux Sable Canada Ltd. are partly owned by the same entity
May 2014
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Canadian Energy Research Institute
In regards to gas processing, CERI estimates that about 60 percent of the gas was processed by
midstream players as opposed to upstream companies in BC, while about 75 percent of the
NGLs were extracted by midstream companies. There are also fewer companies processing gas
and extracting NGLs in BC than in AB, and this is a function of BC being a less mature
development area of the WCSB, but also because development in BC is concentrated in a
smaller geographical area (NE BC) compared to AB.
It is important to highlight that even though we discuss midstream players as producing the
largest share of NGLs in the WCSB, this does not necessarily mean that these companies own
the NGL volumes themselves, but rather the infrastructure required to extract and market
them.
Midstream companies offer their services through a variety of contracting options including
keep-whole agreements,97 percentage of proceeds,98 and fee-based arrangements.99 Fee-based
agreements are common for gathering, processing, fractionation, and marketing, while the
other type of arrangements are more common options in regards to gas processing.
Trends in Midstream Infrastructure Investments
The fact that gas processing in Western Canada is generally dominated by exploration and
production (E&P) or upstream companies but the rest of the midstream value chain is
dominated by third-party midstream companies is tied to historical developments.
Traditionally, most upstream companies built, owned, and operated their own midstream
facilities (from gas processing to NGL marketing) in a more vertically integrated model,100 but
this has been changing over time.
Over the last decade or so midstream companies in the WCSB have grown through a
combination of acquiring assets from upstream players101 but also through industry
consolidation.102
Through these changes, a handful of large midstream companies in the WCSB have emerged.
This trend is also apparent south of the border in the US and was recently discussed in a report
by consultancy Deloitte.103
97
Processor takes ownership of outlet stream and compensates producer for gas removed as NGLs
Processor paid by retaining a portion of the outlet stream revenues
99
Processor compensated per unit
100
This model resembled the historical vertically integrated approach of oil companies owning assets all the way from the
upstream (exploration and production) to the downstream (refining and marketing)
101
Examples include Keyera acquiring Gulf and Chevron’s midstream assets; Plains Midstream acquiring BP Canada’s midstream
assets, as well as Pembina acquiring Talisman’s Cutbank gas processing complex, Veresen acquiring Encana’s Cutbank complex,
and Enbridge acquiring Encana’s Cabin complex
102
Examples include Pembina’s acquisition of Provident Energy, Altagas’ acquisition of Taylor Processing and more recently
Altagas’ acquisition of a portion of Petrogas ($440 MM)
103
The rise of the midstream: Shale reinvigorates midstream growth: https://www.deloitte.com/assets/DcomUnitedStates/Local%20Assets/Documents/Energy_us_er/us_er_RiseOfTheMidstream_Nov2013.pdf
98
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
53
Recently, some large producers in Western Canada have opted to divest some of their
midstream assets in Canada,104 signaling their need to free-up capital to focus on their core
competencies upstream, as well as to cut costs in the currently persistent low gas price
environment. Large producers are also avoiding new plant construction by getting midstream
companies to build them. Alternatively, some companies have opted to avoid any infrastructure
investments altogether while minimizing the number of fees paid for various midstream
services by acquiring rich-gas premiums105 through Alliance and Aux Sable.106
Furthermore, given the prevalence of small companies producing gas in Western Canada, these
smaller companies benefit from third-party infrastructure by avoiding large upfront capital
investments that could be better allocated for their upstream activities. Midstream companies
on the other hand specialize in their processing and marketing competencies and thus result in
better allocation of capital across projects.
While upstream activities have a higher risk profile (see Figure 3.3) this also means that there
are greater returns to be achieved and more cash flow to be generated for E&P companies by
avoiding midstream investments.
Figure 3.3: Oil and Gas Investment Risk and Return Continuum
Midstream
Source: CERI based on PWC
Oilfield Services
Downstream
Upstream
107
This money can then be re-invested and used to grow production. Midstream companies on the
other hand generate steady and low-risk cash flow which allows them to continue to grow their
operations according to market needs.
Another factor influencing investment in midstream infrastructure in Western Canada is the
expected continued increase in NGL volumes. Table 3.1 presents some of the NGL midstream
infrastructure investments that have taken place over the last couple of years and those that are
expected to take place in the coming years in Western Canada.108
104
Encana divested their Cutbank and Cabin gas complexes in Western Canada for over $1B between 2011 and 2012. Talisman
divested their Cutbank processing complex in 2011 for about $330 MM. This trend is also notable in the US with companies
such as Chesapeake, Devon, and Encana
105
Reflects the value of gas and a portion of NGL profits in the US Upper Midwest (Chicago) market rather than the WCSB
106
One of the most notorious recent deals includes a 200 MMcf/d rich-gas premium deal with Encana and Phoenix Duvernay
Gas. See: http://www.auxsable.com/top-navigation/news-room/newsroom-article/18/aux-sable-acquires-additional-long-termliquids-rich-gas-supplies
107
PWC, The US Energy Revolution: The role of private equity in oil and gas, February 2013. http://www.pwc.com/en_GX/gx/oilgas-energy/publications/pdfs/pwc-usenergy-revolution-role-of-private-equity-v2-pdf.pdf
108
Timeframe used is 2011 to 2016. Investments announced include those up until March 2014
May 2014
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Canadian Energy Research Institute
The focus here is mainly on investments made by midstream companies. Since E&P companies’
midstream investments are not included here, the overall investment amount presented here is
deemed to be conservative. These investments range from new gas processing plants to
optimization or expansion of existing assets, as well as expansion of fractionation,
transportation, and storage infrastructure for NGLs (marketing). All in all, these investments add
up to close to $11 billion (B) spent and to be spent between 2011 and 2016, or about $1.8 B per
year, on average. By any measure, these are substantial investments.
There are some common features across these investments. The median investment is close to
$230 MM, which requires significant upfront capital commitments, yet this is capital not spent
by the upstream companies and can be allocated for development. Most of these investments
are generally underpinned by 10+ year commitments from E&P companies, which work as a
guarantee for the midstream companies to recover their capital, but also requires a solid
acreage, reserve base, and drilling program from E&P companies, thus creating certainty and
stability for both parties.
These investments have also been backed by certain utilization thresholds in order to be
sanctioned. Furthermore, these investments are largely underpinned by fee-based agreements
which create a steady cash flow and reduce commodity exposure on the midstream owner,
while allowing E&P companies to maximize the value of NGLs and maximize their cash flow.
While the E&P companies are exposed to the NGLs price volatility (higher risk) they are also
better positioned to get the most reward from it (better returns).
Another important aspect of these investments is that a lot of them are tied to downstream
contracts, particularly for deep cut facilities which are expected to extract additional volumes of
ethane at the field level (primarily as a mix). This has in turn led to required expansion of C2+
NGL pipeline systems and de-ethanization fractionation capacity, as well as ethane and ethylene
storage capacity expansion. These investments have been partially facilitated via government
incentives such as the IEEP. Table 3.2 displays information related to projects associated with
the IEEP.
The primary purpose of the IEEP was to encourage more value-added in AB by addressing the
tight supply of ethane feedstock in order to fully utilize existing petrochemical capacity in the
province. The program was designed to encourage investments in ethane extraction facilities as
well as to attract possible future investment in petrochemical derivative plants.109
This was achieved through a system of ethane royalty credits (to a maximum of $350 MM for
the IEEP at $1.8/bbl for natural gas sources and $5/bbl for off-gases) that gets transferred all the
way from petrochemical end-users to upstream companies for a maximum period of 60 months
(5 years). Petrochemical end-users obtain these credits by providing evidence of increased
utilization above an established baseline level.
109
For more on the IEEP see: http://www.energy.alberta.ca/EnergyProcessing/pdfs/IEEPNov11.pdf
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
55
Table 3.1: Recent Gas Processing/NGL Infrastructure Investments in Western Canada ($MM) (2011 – 2016)
Company
Plant
PRODUCER-OWNED MIDSTREAM DIVESTITURES
Costs ($MM) Capacity (MMcf/d) $MM/ MMcf/d Transaction Date Type
Pembina Pipeline Corporation
Cutbank Complex (Kawka, Cutbank, and Musreau)
$
Veresen/ Encana
Keyera/ Whitecap
Total
Cutbank Complex (Hythe/ Steeprock)
Cynthia Plant (NW Alberta)
$
$
$
330
915
113
1,358 $
425 $
0.8
Location
Cutbank Complex (near Grand
2011 Shallow/ Deep-cut (Musreau) Prairie, AB)
516 $
78 $
1,019
1.8
1.4
2012 Shallow
2014 Deep-cut
Cutbank (BC Montney)
North West Alberta
Notes
Talisman acq. + Expansion
2012 Encana divestiture (Steeprock = 198 MMcf/d (sour)
Hythe = 340 MMcf/d (sweet) , 176 MMcf/d (sour))
Includes some upstream assets
NEW GAS PLANT INVESTMENTS
$MM/ MMcf/d Comissioning Date Type
$
2.0
2012 Deep Cut
$
2.0
2012 Deep Cut
$
0.5
2012 Deep Cut Addition
$
0.3
2012 Co-stream expansion
$
2.0
2013 Deep Cut
2013 Deep Cut
Company
Spectra Energy
AltaGas
Pembina Pipeline Corporation
AltaGas
Spectra Energy
Williams Canada
Plant
Dawson Processing Plant Phase I
Gordondale
Musreau I Expansion
Harmattan Co-Stream
Dawson Processing Plant Phase II
Turbo Expander at Suncor Upgrader
Costs ($MM) Capacity (MMcf/d)
$
400
200
$
235
120
$
101
200
$
87
250
$
400
200
$
225
Pembina Pipeline Corporation
Resthaven
$
230
200 $
1.2
2014 Deep Cut
Cutbank Complex (AB)
Paramount Resources
Musreau Deep Cut
$
230
200 $
1.2
2014 Deep Cut
Cutbank Complex (AB)
Pembina Pipeline Corporation
QuickSilver Resources
Keyera Corp.
Saturn I
Fortune Creek Gas Plant
Simonette (Modifications)
$
$
$
200
175
90
200 $
150 $
100 $
1.0
1.2
0.9
2014 Deep Cut
2012 Shallow Cut
2014 Shallow Cut/ Deep Cut
Saturn Complex (near Hinton,
AB)
Horn River (NE BC)
NW AB
Enbridge
Cabin Gas Plant Complex
$
1,100
800 $
1.4
2015 Shallow Cut
Horn River
Williams Canada
Keyera Corp.
Pembina Pipeline Corporation
Pembina Pipeline Corporation
Mistral Midstream/ SaskEnergy
Total
Cryogenic Off-Gas Plant at CNRL Horizon Upgrader
Rimbey Turbo Expander
Musreau II
Saturn II
Viewfield (SK), Bakken Straddle Plant
$
$
$
$
$
$
300
210
110
170
75
4,338
3.6
0.5
1.1
0.9
1.5
2015
2015
2015
2015
2015
Fort Mc. Murray
West Central AB
Cutbank Complex (AB)
Saturn Complex (AB)
Viewfield (SK)
83
400
100
200
50
3,474
$
$
$
$
$
Deep Cut (C2+/C2= Mix)
Deep Cut
Shallow Cut
Deep Cut
Deep Cut Straddle Plant
Location
Dawson Creek (NE BC)
Gordondale Area (AB)
Cutbank Complex (AB)
Cochrane/ Harmattan
Dawson Creek (NE BC)
Fort Mc. Murray
NGLs Capacity
(kb/d)
Notes
n/a
n/a
Long-term EnCana Contract
11
Construction + Expansion/ Encana. Operational in Feb 2012
10
Co-stream project (similar to a straddle plant)
n/a
n/a
n/a
Process modification or addiiton of Turbo Expander
10
13 kb/d extraction, modification & expansion of shallow cut gas
plant
13
Q42013, 100% owned by Paramount (~30 kb/d NGLs, 10 kb/d
(33%) C2)
30
100% contracted, 10 yr (connected to Talisman's Wild River &
Bigstone gas plants. Talisman to increase recoveries to ~70
bbl/MMcf from ~10 bbl/ MMcf). Total 13.5 kb/d of NGLs (70%
C2). Late 2013
14
Phase I. Total capacity all phases: ~600 MMcf/d = $760 MM
n/a
NuVista Energy contract/ Possible future deep-cut
n/a
Two phases of 400 MMcf/d each for about 800 MMcf/d (Phase
I: 2012, Phase II: 2015)
n/a
Includes pipeline connection to Boreal pipeline and supporting
facilities
18
Long-term ethane purchase agreement
20
Gas Plant + Associated Facilities
5
65% contracted, 10 yr (130 MMcf/d, 13 kb/d NGLs)
13
To be tied to Vantage Pipeline
4
147
bbl/MMcf
n/a
90
50
n/a
n/a
n/a
65
150
68
n/a
n/a
n/a
217
50
50
65
80
NGLS FRACTIONATION INVESTMENTS
Company
Pembina Pipeline Corporation
Williams Canada
Plant/ Fractionator
Rewater Fort Saskatchewan (RFS) Expansion
De-ethanizer at Redwater
Costs ($MM) Capacity (kb/d)
$MM/ kb/d
Comissioning Date Type
$
15
8 $
1.9
2012 C2+ Fractionator
$
225
17 $
13.2
2013 De-ethanizer
Location
Fort Saskatchewan
Fort Saskatchewan
Keyera Corp.
Pembina Pipeline Corporation
Williams Canada
Keyera Corp.
Pembina Pipeline Corporation
Pembina Pipeline Corporation
Total
Keyera Fort Saskatchewan (KFS) Expansion
Rewater Fort Saskatchewan (RFS) Twinning = RFS II
Redwater Expansion
KFS Twinning
RFS I & II Debottlenecks
RFS III
$
$
$
$
$
$
$
Fort Saskatchewan
Fort Saskatchewan
Fort Saskatchewan
Fort Saskatchewan
Fort Saskatchewan
Fort Saskatchewan
145
415
300
220
65
400
1,785 $
30
73
13
35
18
73
267
$
$
$
$
$
$
4.8
5.7
23.1
6.3
3.6
5.5
2014
2015
2015
2016
2016
2016
De-ethanizer
C2+ Fractionator
Required expansion
C3+ Fractionator
Debottlenecks
C2+ Fractionator
Notes
2012 Completion
Adding de-C2 capacity
Underpinned by a large deep basin producer (Possibly
Paramount)
97% contracted, 10 yr, C2 to NOVA Chem.
Expansion required to accommodate growing volumes
Twinning of KFS. Increasing capacity to 65 kb/d
Debottleneck increases each frac capacity by 9 kb/d
(CERI Speculative, most likely to proceed given pipeline exp.)
May 2014
56
Canadian Energy Research Institute
NGLs PIPELINES INVESTMENTS
Company
System
Williams Energy Canada
Plains Midstream
Boreal Pipeline Construction
Rainbow Pipeline II NGL Expansion
NGL Expansions (HVP System: Northern + Peace)
Phases I + II
Vantage Pipeline
Peace LVP (Crude + Condensate)
Cochin Pipeline Reversal
Phase III Expansion (assumes 50% allocation of $2B
announcement to NGLs infrastructure and 50% to
crude oil infrastructure: CERI assumption)
Pembina Pipeline Corporation
Mistral Midstream
Pembina Pipeline Corporation
Kinder Morgan
Pembina Pipeline Corporation
Total
Costs ($MM) Capacity (kb/d)
Comissioning Date Type
43
$
7.0
2012 HVP Pipeline (New build)
2013 LVP System Expansion
Location
Ft. McMurray --> Fort
Saskatchewan
NW AB --> Fort Saskatchewan
515
300
280
260
105
43
95
95
$
$
$
$
4.9
7.0
2.9
2.7
2014
2014
2014
2014
NW AB --> Fort Saskatchewan
Bakken (ND,SK) --> AEGS
NW AB --> Fort Saskatchewan
US Midwest --> AB
1,000
2,855
135
381
$
7.4
2016 HVP & LVP System Expansion NW AB --> Fort Saskatchewan
$
$
300
200
$
$
$
$
$
$
$MM/ kb/d
n/a
HVP System Expansion
HVP Pipeline (Spec C2)
LVP System Expansion
Flow Reversal
OTHER NGLs ASSOCIATED MIDSTREAM INVESTMENTS
Company
Keyera Corp.
Pembina Pipeline Corporation
Pembina Pipeline Corporation
Total
Asset
South Cheecham Rail & Truck Terminal
Cavern Development & Terminal/ Hub Services
RFS II upsize/ Accommodate RFS III Prospect
Costs ($MM) Comissioning Date
$
68
2013
$
375
2014
$
25
2014
$
468
Deep Cut Plants Expansion & New Builds / Straddle Plants/ Co-stream Facilities
$468
4%
$1,785
17%
$2,953
27%
NGLs Pipelines
Other Gas Processing/ NGLs Extraction Facilities (Mainly Shallow Cut)
$1,358
13%
Producer-owned Midstream Divestitures
$1,385
13%
$2,855
26%
NGLs Fractionation
Other Midstream Assets (Storage & Logistics)
Total: $10,804 MM (2011 - 2016)
Source: BCMJTST,
110
111
110
Industry data, CERI research, and GOA data.
111
Tables and figure by CERI
British Columbia Ministry of Jobs, Tourism and Skills Training, Major Projects Inventory, June 2013: http://www.jtst.gov.bc.ca/ministry/major_projects_inventory/index.htm
Government of Alberta (GOA), Inventory of Major Projects: https://www.albertacanada.com/business/statistics/inventory-of-major-projects.aspx
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
57
Table 3.2: Alberta's Incremental Ethane Extraction Program (IEEP): Projects Information,
2012112
Applicant
Dow Chemicals
Dow Chemicals
C2 Volumes
Description
(kb/d)
Increasing the C2 recovery at the Empress V plant
7
Modification of Keyera's Rimbey Gas Plant to
5
optimize removal and extraction of C2
Installation of equipment enabling capture of
10
ethane and ethylene out of off-gases
Pipeline valve and piping cross-over installations to
3
direct NGL rich gas Alberta extraction plants
Installation of equipment and pipeline
9
infrastructure to optimize extraction and removal of
C2
Installation of equipement and modfication of
6
existing process to maximize C2 extraction and
removal
Alteration of exisitng infrastructure at Waterton to
1
increase NGL recovery in Alberta at export point
Installation of various equipment and modification
1
of processes to extact C2 from Scotford refinery
Project
Empress V Deep Cut Project
Rimbey Ethane Extraction Project
NOVA Chemicals Williams Off-Gas Ethane Extraction Project (Phase I)
NOVA Chemicals Hidden Lake Streaming Project
NOVA Chemicals Harmattan Plant Co-Stream Project
Royalty Credits
($MM)
Status
$
23 Approved (2008)
$
16 Approved (2008)
Expected Onstream
Date
Onstream
Onstream
$
33 Approved (2010) 2014
$
9 Approved (2010) n/a
Commissioned
Delivery Point
by
IPF/ Plains
AEGS
Keyera
AEGS
Williams
NGTL
Petrochemical
Facility (via Boreal)
n/a
$
30 Approved (2011) Onstream
Altagas
AEGS
$
20 Approved (2011) Onstream
Pembina
HVP Pipeline to Ft. Sk.
(Fractionators)
$
3 Approved (2011) Onstream
Shell
AEGS
$
4 Approved (2011) Onstream
Shell
Petrochemical
Facility (on site)
Dow Chemicals
Musreau Deep Cut Project
Shell Chemicals
Shell Waterton Incremental NGL Recovery Project
Shell Chemicals
Scotford Fuel Gas Recovery Project
Dow Chemicals
Rimbey Turbo Expander Project
Modification of exisitng Rimbey gas plant by
installing a turbo expander to improve C2 recovery
15 $
49 Approved (2012) 2015
Keyera
AEGS
NOVA Chemicals Williams Off-Gas Ethane Extraction Project (Phase II)
Increase the ethane removed from off-gases from 10
to 17 mb/d
Modification and expansion of existing gas plant for
C2 extraction in NW Alberta
Installationf of infrastructure capable of capturing
ethane off-gases from Scotford Upgrader
Construction of a new gas processing plant in NW
Alberta which will capture ethane from natural gas
production
Increase of storage capacity and plant
modifications to improve utilization of the existing
facility for C2 extraction
Aggregation of several small investments to improve
efficiency at Jumping Pound facility for improved C2
extraction
Modification of the existing Saturn Gas plant with
the installation of a cryogenic turbo expander to
improve C2 extraction
7 $
64 Approved (2012) 2015
Williams
7 $
21 Approved (2012) 2015
Pembina
3 $
27 Approved (2012) Onstream
Shell
4 $
13 Approved (2012) Onstream
Altagas
Petrochemical
Facility (via Boreal)
HVP Pipeline to Ft. Sk.
(Fractionators)
Petrochemical
Facility (on site)
HVP Pipeline to Ft. Sk.
(Fractionators)
Dow Chemicals
Resthaven Facility Phase 1
Shell Chemicals
Shell Scotford Upgrader Off-gas Project
NOVA Chemicals AltaGas-Gordondale Deep Cut Project
NOVA Chemicals Judy Creek Ethane Extraction Project
Shell Chemicals
Shell Jumping Pound Project
Dow Chemicals
Project Turbo (Saturn Plant)
Total
Source: CERI research, and ADOE
16
113
3 $
9 Approved (2012) n/a
n/a
HVP Pipeline to Ft. Sk.
(Fractionators)
1 $
3 Approved (2012) Onstream
Shell
AEGS
Pembina
HVP Pipeline to Ft. Sk.
(Fractionators)
8 $
89 $
27 Approved (2012) 2014
351
data. Table by CERI
CERI estimates that a total of close to 90 kb/d of incremental C2 have been approved under the
IEEP between 2008 and 2012 and that the $350 MM available to the program are completely
allocated.
CERI also estimates that of the midstream investments listed in Table 3.2, about $4 B are
directly114 (45 percent) and indirectly115 (55 percent) tied to the IEEP. Further including
downstream ethylene derivative investments in the province (discussed in next section) brings
that total amount to about $5 B.
112
It is important to note that the IEEP is now fully subscribed and the AB government has not (as of the time of writing)
indicated any extensions to the program
113
Alberta Energy, Our Business, Energy Processing, Incremental Ethane Extraction Regulation:
http://www.energy.alberta.ca/EnergyProcessing/1349.asp
Alberta Energy, Annual Report 2012-2013: http://www.energy.alberta.ca/Org/Publications/AR2013.pdf
114
Extraction plant builds, modifications, and expansions for incremental ethane extraction
115
Required expansions and modifications in pipeline and fractionation capacity to get incremental C2 volumes to end-users
May 2014
58
Canadian Energy Research Institute
The build-out of midstream infrastructure will be significant over the coming years as producers
focus on upstream development while attempting to maximize profitability via monetization of
valuable NGLs. Meanwhile, midstream companies will provide connections between producers
and end-users.
Given these investments, CERI estimates that by 2018116 NGL pipeline capacity to Fort
Saskatchewan will almost double from under 400 kb/d of capacity in 2012 to well over 700
kb/d. Meanwhile, fractionation capacity in the area is expected to match this significant growth
with capacity increasing from under 300 kb/d in 2012 to close to 500 kb/d of capacity by 2018.
Furthermore, C2+ fractionation capacity is estimated to account for 70 percent of total
fractionation capacity by 2018, compared to under 50 percent in 2012 (Figure 3.4)
Figure 3.4: NGL Pipeline Capacity (Top) and Fractionation Capacity (Bottom) in the
Fort Saskatchewan Area (kb/d), 2002 – 2018
800
754
Alberta Liquids Pipeline System (ALPS)*
Peace LVP System Expansion (Phase III)
700
644
Peace LVP System Expansion (Phase II)
Peace LVP System Expansion (Phase I)
600
517
kb/d
Peace HVP System Expansion (Phase II)
483
500
400
Peace HVP System Expansion (Phase III)
542
Peace HVP System Expansion (Phase I)
451
385
385
385
385
385
385
385
385
385
385
Judy Creek
396
Bonnie Glen
Suncor Ft. Mac -> Ft. Sk. (to 2012)/ Boreal (2012 onwards)
300
Northern System
Peace LVP System (Condensate)
200
Brazeau NGL Gathering System
Cochrane-Edmonton (Co-Ed) System
Peace HVP System (NGLs)
100
Total NGLs Pipeline Capacty to Fort Saskatchewan
*CERI Estimate
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
600
Williams Redwater Expansion II (Syncrude)*
Williams Redwater Expansion I (CNRL)
KFS II
RFS III
RFS II
Williams Redwater
Keyera Fort Saskatchewan (KFS)
Dow Fort Saskatchewan (DFS)
Redwater Fort Saskatchewan (RFS)
BP Fort Saskatchewan
Total Fort Saskatchewan Fractionation Capacity (kb/d)
Total C2+ Fractionation Capacity
500
kb/d
400
300
*CERI Estimate
492
497
2017
2018
432
339
289
289
289
289
289
289
289
289
289
289
296
296
296
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
200
100
-
Source: CERI
116
Latest date for which expansions have been announced as of the time of writing
May 2014
2015
2016
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
59
Beyond 2018, midstream investments in NGL pipeline and fractionation capacity may be
required or sufficient based on the NGL outlook. On the other end, investments in downstream
infrastructure will also be required in order to expand existing end-use markets or in order to
reach new markets. This is briefly discussed next.
Downstream Investments Associated with Increasing NGL Supplies in
Canada
Table 3.3 illustrates recent/ongoing downstream investments targeting increased NGL use in
Canada.
Table 3.3: Recent and Announced NGL Downstream Investments in Canada ($MM)
(2013 – 2016)
Company
Nova Chemicals
Nova Chemicals
Nova Chemicals
Williams Canada
Pembina Pipeline Corporation
Altagas
Total
Asset/ Notes
Costs ($MM) Comissioning Date
Ontario Cracker Revamp (increase NGLs use/ reduce
heavy feed)
$
250
2013
PE1 Expansion (Building R3)/ E2 Upgrades &
Refurbishment
$
1,000
2015
Sarnia Growth Projects (Expansion + Debottlenecks) $
300
2016
Propane Dehydrogenation (PDH) Plant
$
900
2016
LPG Export Terminal
$
1,000
2015
LPG Export Terminal
$
500
2016
$
3,950
LPG Export Terminals
$900
23%
$1,500
38%
Ethane/ Ethylene Petrochemicals
Propane Petrochemicals (PDH)
$1,550
39%
Total: $3,950 MM (2011 - 2016)
Source: CERI research and Industry data. Table and figure by CERI
Total downstream NGL investments in Canada are estimated to be close to $4 billion (B)
between 2013 and 2016, or an average of $1B per year.
May 2014
60
Canadian Energy Research Institute
There are two primary categories of identified downstream investments: investments related to
petrochemical facility expansion and new builds, including ethylene and propylene-chain
petrochemical plants totalling close to $2.5 B (or 62 percent of total downstream investments);
and LPG export terminals117 totalling $1.5 or 38 percent total downstream investments. This is a
significant level of investment by any means.
Adding midstream investment estimates of $10.8 B, total NGL-related investments (midstream
plus downstream) of close to $14.8 B are estimated to have taken and to take place in Canada
between 2011 and 2016, at an average of $2.5 B per year. Clearly, shale gas production and NGL
availability have created a positive outlook for monetizing and using NGLs in Canada.
These investments are expected to affect NGL industry participants from across the upstream to
the downstream spectrum.
Upstream participants (WCSB producers) are looking for opportunities to expand and diversify
markets for their NGLs output both at home and abroad, with the end goal of increasing their
profitability and growing their operations by obtaining the best possible netbacks for their
output.
At home, this will require the expansion of NGL end-uses through the expansion of existing
industries and facilities (such as ethylene crackers) or the creation of new industries (propylene
via PDH).
Expanding into markets abroad will require diversifying their customer base from a US-centered
one to a more global one in nature. Given its close proximity to Canada and the prospects for
increased energy demand in the Asia-Pacific region, this region presents the best option for new
trading partners to WCSB producers.
As exports diversify geographically, NGL end-users in Canada will compete for the same
commodities with their peers across the Pacific.
How competitive the Canadian petrochemical industry remains in the global context, and what
impact Canadian (and North American) LPG supplies118 can have in the global market will
determine the marketing options for Canadian NGLs, as well as their opportunities and
challenges.
In order to better understand North American and global markets for NGLs the next two reports
of the NGL update series (Parts III & IV) will discuss supply and demand balances, as well as
pricing and economics (together, market fundamentals) around the NGLs supply chain.
117
While CERI acknowledges that LPG export terminals are essentially transportation infrastructure and thus more akin to
midstream rather than downstream infrastructure, once LPG has been shipped to a destination it could be used as either energy
or transformed to petrochemicals. Thus, LPG export terminals are the delivery point for WCSB producers and are classified in
this section as downstream infrastructure
118
North American LPG projects are discussed in more detail in Part III
May 2014
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
61
Part III will focus on supply and demand balances for NGLs in North America with a more
detailed and in-depth focus on Canada. Part IV will discuss global NGL markets and will place
into context opportunities and challenges for Canadian NGL players, from the upstream to the
downstream, in accessing global markets and competing with other suppliers to gain market
share.
May 2014
62
May 2014
Canadian Energy Research Institute
Natural Gas Liquids (NGLs) in North America – An Update
Part II – Midstream and Downstream Infrastructure
63
Appendix I – Canadian NGL Infrastructure
Source: CERI from PennWell MAPSearch
May 2014
64
Canadian Energy Research Institute
Appendix II – United States NGL Infrastructure
Source: CERI from PennWell MAPSearch
May 2014