Study No. 139 May 2014

NATURAL GAS LIQUIDS (NGLS) IN CANADIAN ENERGY NORTH AMERICA: AN UPDATE RESEARCH INSTITUTE 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 iii Part II – Midstream and Downstream Infrastructure Table of Contents

LIST OF FIGURES ...... v LIST OF TABLES ...... vii EXECUTIVE SUMMARY ...... 1 NGL INFRASTRUCTURE AND NGL END-USERS IN CANADA ...... 3 Natural Gas Field Processing Plants and Straddle Plants ...... 3 Fractionators ...... 11 Pipelines and Other Transportation Infrastructure ...... 13 Natural Gas Transmission and Distribution Systems ...... 13 Liquids Transportation System ...... 15 Rail Transportation Infrastructure ...... 21 Refineries, Upgraders, and Off-gas Processing Plants ...... 23 Petrochemical Facilities: Steam Crackers, Aromatic Plants, Derivative Plants, and Others ...... 24 NGL INFRASTRUCTURE AND NGL END-USERS IN THE UNITED STATES ...... 35 Natural Gas Processing Plants ...... 35 Fractionators ...... 38 Pipelines and Other Transportation Infrastructure ...... 42 Liquids Transport Infrastructure ...... 42 Petrochemical Facilities ...... 45 ANALYSIS: INFRASTRUCTURE INVESTMENTS IN CANADA TO CONNECT NGL SUPPLY AND DEMAND ...... 49 Major Midstream Players in Western Canada ...... 49 Trends in Midstream Infrastructure Investments ...... 52 Downstream Investments Associated with Increasing NGL Supplies in Canada ...... 59 APPENDIX I – CANADIAN NGL INFRASTRUCTURE ...... 63 APPENDIX II – UNITED STATES NGL INFRASTRUCTURE ...... 64

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May 2014 Natural Gas Liquids (NGLs) in North America: An Update v Part II – Midstream and Downstream Infrastructure List of Figures

1.1 Illustrative Canadian NGL Supply and Demand Flowchart ...... 4 1.2 Gas Processing and NGL Extraction Process ...... 5 1.3 Gas Gathering, Processing, and Transmission System in NE BC, Gas Distribution System, and NGL Gathering System ...... 6 1.4 Western Canada Natural Gas Processing and Transportation System ...... 7 1.5 Map of Deep-cut Field Gas Processing Plants in the WCSB ...... 10 1.6 Canadian Natural Gas Transportation Infrastructure and Distribution Companies/Areas ...... 13 1.7 Canadian Crude Oil Pipeline System ...... 16 1.8 Canadian NGL Pipeline Infrastructure Capacities, and Main NGL Storage Facilities and Capacities ...... 17 1.9 NGLs Transported to Fort Saskatchewan and Pipeline Capacity and Peace LVP System Throughput Estimates and Capacity ...... 18 1.10 North America’s Rail Transportation Network ...... 22 1.11 Petrochemical Feedstock and End-use Flowchart ...... 25 1.12 Moving Up the Value Chain from Hydrocarbons to End-use Products ...... 25 1.13 Canadian Petrochemical Production and 2012 % Share of Total ...... 31 1.14 Total Petrochemical Production in Canada by Source, and Estimated Ethylene Production from Steam Crackers by Feedstock ...... 33 2.1 Gas Processing Capacity in the United States Lower 48 ...... 35 2.2 US Lower 48 Gas Processing Capacity Additions by Region, 2011-2016 ...... 37 2.3 US Lower 48 Gas Processing Capacity by Region, 2004-2016 ...... 38 2.4 Marcellus/Utica Gas Processing Capacity, 2004-2016 ...... 38 2.5 US Fractionation Capacity by Region and by Operator, 2012 ...... 39 2.6 Fractionation Capacity Additions by Area and Operator, 2011-2016 ...... 40 2.7 US Fractionation Capacity by Region ...... 41 2.8 Marcellus/Utica Total Fractionation and De-ethanization Capacity ...... 41 2.9 Major NGL Pipeline Corridors and Fractionation Centers in the United States ...... 43 3.1 Top Natural Gas/NGL Players in AB: Natural Gas Production and Field Processing, NGLs Extraction ...... 50 3.2 Top Natural Gas Processing/NGL Extraction Players in BC ...... 51 3.3 Oil and Gas Investment Risk and Return Continuum ...... 53 3.4 NGL Pipeline Capacity and Fractionation Capacity in the Fort Saskatchewan Area, 2002-2018 ...... 58

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May 2014 Natural Gas Liquids (NGLs) in North America: An Update vii Part II – Midstream and Downstream Infrastructure List of Tables

1.1 Information on Deep-cut Field Gas Processing Plants in the WCSB ...... 9 1.2 WCSB Straddle Plant Information, AB Straddle Plants Processing Volumes and Utilization ...... 11 1.3 Total Canadian Fractionation Capacity and Fort Saskatchewan Fractionators NGL Production and Capacity Utilization/Stand-alone Fractionation Capacity Information ...... 12 1.4 Large Canadian Midstream Companies NGL Rail Handling Facilities and Rail Car Fleet ...... 23 1.5 Canadian Refining and Upgrading Capacity and Off-gas Processing Plants ...... 24 1.6 Canadian Petrochemical Plant Information ...... 27 1.7 Major Petrochemical Clusters in Canada, Summary ...... 29 2.1 Natural Gas Processing Plants, Number and Capacity by PADD and Top 50 Owners’ Capacity in the US Lower 48 ...... 36 2.2 US NGL Pipelines ...... 44 2.3 US Ethylene Cracking Capacity by Region/Company and Estimated Feedstock Requirements ...... 46 2.4 US Petrochemical Facility Expansions and New Constructions ...... 47 3.1 Recent Gas Processing/NGL Infrastructure Investments in Western Canada ...... 55 3.2 Alberta’s Incremental Ethane Extraction Program: Projects Information, 2012 ...... 57 3.3 Recent and Announced NGL Downstream Investments in Canada ...... 59

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May 2014 Natural Gas Liquids (NGLs) in North America – An Update 1 Part II – Midstream and Downstream Infrastructure 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, re- purposing, 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 divestitureand 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 3 Part II – Midstream and Downstream Infrastructure NGL Infrastructure and NGL End-Users in Canada

While the previous report offered some insight in regards to the different sources ofNGL 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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Figure 1.1: Illustrative Canadian NGL Supply and Demand Flowchart

UPSTREAM (SOURCES) MIDSTREAM (PROCESSING & TRANSPORTATION) DOWNSTREAM (END-USE MARKETS) Transporation Refineries & Crude Oil Infrastructure Upgraders

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 Sales Raw Gas Gas 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 5 Part II – Midstream and Downstream Infrastructure 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 Sweet Raw Gas Raw Gas Raw Gas Raw Gas NGLs Mix

H2S & CO2 Spec NGLs Inlet Gathering & NGLs Removal NGLs Separator Compression Markets (Sweetening) Extraction

Fractionation

Sulphur to Market to Sulphur

Acid/

Sales

Disposal

Market Market

Water

Sour GasSour Gas to to Gas

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 4 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

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Figure 1.3: Gas Gathering, Processing, and Transmission System in NE BC (top), Gas Distribution System (bottom left), and NGL Gathering System (bottom right)

Sources: Top chart: Spectra Energy5/Bottom left: PNG;6 Bottom right: Pembina Pipelines7

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.wei- pipeline.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

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 7 Part II – Midstream and Downstream Infrastructure 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)

Sources: Data from AER,8 BCMNGD, CERI research, Industry data,9 NEB,10 and OGJ.11 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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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) 14 into spec NGLs such as purity C2 to be delivered to markets.

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

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 9 Part II – Midstream and Downstream Infrastructure Table 1.1: Information on Deep-cut Field Gas Processing Plants in the WCSB (2012)

ALBERTA DEEP CUT PLANTS REGULAR DEEP CUT FACILITIES Gas Processing 2012 Gas Utilizatio NGLs Extraction 2012 NGLs Utilization 2012 Plant Owner/ Operator Capacity Processed Products Area SA n (%) Capacity (kb/d) (kb/d) (%) bbl/ MMcf (MMcf/d) (MMcf/d) ELMWORTH 4-8-70-11W6 ConocoPhillips Canada (BRC) Partnership 689 328 48% 16 6 39% 20 C2+ Mix PIA14 Foothills SEMCAMS KAYBOB SOUTH #3 SemCAMS ULC 637 246 39% 66 7 11% 29 C2+ Mix PIA15 Foothills SHELL CAROLINE Shell Canada Energy 364 124 34% 61 8 13% 64 C2+ Mix PIA03 Foothills DEVON ELMWORTH Devon Canada 332 309 93% 18 17 97% 55 C2+ Mix PIA14 Foothills MUSREAU 4-25-62-6W6 Pembina Gas Services Ltd. 281 200 71% 24 6 27% 32 C2+ Mix PIA14 Foothills KEYERA STRACHAN 11-35-037-09W5 Keyera Energy Ltd. 260 175 67% 21 7 36% 42 C2+ Mix PIA09 Foothills DEVON DUNVEGAN Devon Canada 227 72 32% 11 4 33% 53 C2+ Mix PIA17 Northern HUSKY RAINBOW 10-10 Husky Oil Operations Limited 225 122 54% 43 14 32% 113 C2+ Mix PIA22 Northern TRILOGY KAYBOB Trilogy Resources Ltd. 201 102 51% 22 1 4% 8 C2+ Mix PIA15 Foothills Encana Resthaven 8-11-60-3W6 GP Encana Corporation 189 90 48% 15 2 10% 17 C2+ Mix PIA13 Foothills CRESTAR WEMBLEY Conocophillips Canada Energy Partnership 130 61 47% 19 5 24% 74 C2+ Mix PIA14 Foothills GORDONDALE GAS PLANT AltaGas Ltd. 114 14 12% 10 1 5% 40 C2+ Mix PIA14 Foothills KEYERA BIGORAY PLANT 10-07-051-09W5 Keyera Energy Ltd. 80 29 37% 5 2 38% 65 C2+ Mix PIA10 Foothills IMPERIAL WEST PEMBINA Imperial Oil Resources 74 51 69% 11 3 25% 53 C2+ Mix PIA10 Foothills ATCO GOLDEN SPIKE ATCO Energy Solutions Ltd. 62 7 12% 3 0 16% 62 C2+ Mix PIA11 Foothills CHEVRON ACHESON Penn West Petroleum Ltd. 32 7 21% 4 1 19% 106 C2+ Mix PIA11 Foothills HUSKY BIVOUAC Husky Oil Operations Limited 28 - n/a n/a - n/a n/a C2+ Mix PIA21 Northern BONAVISTA CESSFORD Journey Energy Inc. 6 1 11% 0 0 41% 3 C2+ Mix PIA07 Plains TALISMAN BENSON PEMBINA 08-30 NEP Canada ULC 1 0 19% 0 0 0% 0 C2+ Mix PIA11 Foothills Total Deepcut Plants 19 3,932 1,937 49% 349 83 24% 43

DEEP CUT FACILITIES WITH FRACTIONATION Gas Processing 2012 Gas Utilizatio NGLs Extraction 2012 NGLs Utilization 2012 Plant Owner/ Operator Capacity Processed Products Area SA n (%) Capacity (kb/d) (kb/d) (%) bbl/ MMcf (MMcf/d) (MMcf/d) SOLEX HARMATTAN-E LKTON Taylor Processing Inc. 466 167 36% 72 16 22% 94 Spec C2/ Spec or Mix C3+ PIA03 Foothills KEYERA HOMEGLEN-RI MBEY 2-05-44-01W5 Keyera Energy Ltd. 400 301 75% 38 26 69% 86 Spec C2/ Spec or Mix C3+ PIA06 Foothills SHELL WATERTON Shell Canada Energy 270 119 44% 15 4 26% 32 Spec C2/ Spec or Mix C3+ PIA02 Foothills SHELL JUMPING POUND Shell Canada Energy 258 126 49% 8 5 61% 40 Spec C2/ Spec or Mix C3+ PIA03 Foothills BLAZE BRAZEAU RIVER Blaze Energy Ltd. 175 62 36% 20 4 22% 69 Spec C2/ Spec or Mix C3+ PIA10 Foothills PENGROWTH JUDY CREEK Pengrowth Energy Corporation 163 37 23% 30 7 25% 200 Spec C2/ Spec or Mix C3+ PIA15 Foothills KNOPCIK 9-10-74-11W6 Canadian Natural Resources Limited 67 28 42% 2 2 100% 64 Spec C2/ Spec or Mix C3+ PIA14 Foothills CONOCO PECO ConocoPhillips Canada Resources Corp. 66 44 67% 6 2 32% 46 Spec C2/ Spec or Mix C3+ PIA09 Foothills AMOCO WILLESDEN GREEN Penn West Petroleum Ltd. 57 30 52% 1 1 76% 38 Spec C2/ Spec or Mix C3+ PIA09 Foothills RENAISSANCE SYLVAN LAKE-21 Husky Oil Operations Limited 28 13 45% 1 1 65% 57 Spec C2/ Spec or Mix C3+ PIA06 Foothills NEWPORT GILBY Harvest Operations Corp. 19 6 32% 0 0 37% 30 Spec C2/ Spec or Mix C3+ PIA10 Foothills MAGIN THREE HILLS CREEK Penn West Petroleum Ltd. 11 3 28% 1 0 8% 14 Spec C2/ Spec or Mix C3+ PIA06 Foothills 00/06-15-048-03 W5 Pembina GP Sinopec Daylight Energy Ltd. 7 5 77% 0 0 100% 32 Spec C2/ Spec or Mix C3+ PIA11 Foothills BATTLE 1-24-45-8 W4 Penn West Petroleum Ltd. 2 0 22% 4 0 0% 4 Spec C2/ Spec or Mix C3+ PIA08 Plains Total Deepcut Plants w/ Fractionation 14 1,989 942 47% 198 68 34% 72

BRITISH COLUMBIA DEEP CUT PLANTS Gas Processing 2012 Gas Utilizatio NGLs Extraction 2012 NGLs Utilization 2012 Plant Owner/ Operator Capacity Processed Products Area SA n (%) Capacity (kb/d) (kb/d) (%) bbl/ MMcf (MMcf/d) (MMcf/d) Spectra Dawson Processing Plant SPECTRA ENERGY MIDSTREAM CORPORATION 200 40 20% n/a 0.1 n/a 2 C2+ Mix 33 Foothills WEST STODDART CANADIAN NATURAL RESOURCES LIMITED 120 57 47% 5.5 1.8 32% 31 C2+ Mix 34 Foothills FARRELL TALISMAN ENERGY INC. 99 117 118% 0.1 0.1 90% 1 C2+ Mix 41 Foothills CONOCOPHILLIPS RING C-81-I/94-H-9 CONOCOPHILLIPS CANADA OPERATIONS LTD. 64 40 62% 2.5 1.4 56% 35 C2+ Mix 36 Northern DAWSON ARC RESOURCES LTD. 60 119 198% 0.7 0.6 90% 5 C2+ Mix 33 Foothills Canbriam Altares CANBRIAM ENERGY INC. 50 18 36% 1.7 1.0 60% 57 C2+ Mix 41 Foothills CHINCHAGA TAQA NORTH LTD. 50 8 17% 0.4 0.1 35% 18 C2+ Mix 35 Northern SEPTIMUS AUX SABLE CANADA LTD. 50 32 65% 1.0 0.9 90% 28 C2+ Mix 32 Foothills CNRL CLEARHILLS 16-11-88-13 GAS PLANT (AB-XB)CANADIAN NATURAL RESOURCES LIMITED 46 24 51% 0.5 0.3 55% 11 C2+ Mix 34 Foothills CARIBOU KEYERA ENERGY LTD. 40 37 91% 1.0 0.4 42% 12 C2+ Mix 41 Foothills DUKE GAS PLANT 5-23-80-13 (AB) SPECTRA ENERGY MIDSTREAM CORPORATION 40 20 51% 0.3 0.1 22% 3 C2+ Mix 33 Foothills BLAIR ALTAGAS LTD. 32 29 89% 0.2 0.2 90% 7 C2+ Mix 41 Foothills PARKLAND ARC RESOURCES LTD. 28 30 105% 0.9 0.7 76% 24 C2+ Mix 33 Foothills SUNRISE 3-18-80-17 TOURMALINE OIL CORP. 25 68 272% 1.5 1.3 90% 20 C2+ Mix 33 Foothills Duke Fourth Creek 16-11-82-09 SPECTRA ENERGY MIDSTREAM CORPORATION 13 10 79% 0.1 0.1 76% 5 C2+ Mix 33 Foothills SUNSET SHELL CANADA LIMITED 12 13 105% 0.3 0.2 85% 16 C2+ Mix 32 Foothills Total 931 663 71% 16.7 9.4 56% 14

SASKATCHEWAN DEEP CUT PLANTS Gas Processing 2012 Gas Utilizatio NGLs Extraction 2012 NGLs Utilization 2012 Plant Owner/ Operator Capacity Processed Products Area SA n (%) Capacity (kb/d) (kb/d) (%) bbl/ MMcf (MMcf/d) (MMcf/d) Steelman Plains Midstream 16 13 80% n/a 3.6 n/a 273 Spec C2/ Spec or Mix C3+ 56 Plains Kisbey ATCO Midstream 5 2 40% n/a 0.3 n/a 126 Spec C2/ Spec or Mix C3+ 56 Plains Glen Ewen Plains Midstream 3 2 80% n/a 0.3 n/a 126 C2+ or C3+ Mix 56 Plains Glen Ewen Cresecent Point Resources 3 2 80% n/a 0.3 n/a 105 C2+ or C3+ Mix 56 Plains Lougheed Arc Energy Trust 1 1 80% n/a 0.4 n/a 503 C2+ or C3+ Mix 56 Plains Total 28 21 73% 4.8 231 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 11 Part II – Midstream and Downstream Infrastructure Table 1.2: WCSB Straddle Plant Information (2012)17 (Top), AB Straddle Plants Processing Volumes (MMcf/d) and Utilization (%) (2002 – 2012) (Bottom)

2012 Processing 2012 Gas NGLs Utilization NGLs Utilization Owner/ Operator Capacity Processed Capacity NGLs Ownership (%) Extracted (%) (MMcf/d) (MMcf/d) (kb/d) (kb/d) Empress I: Plains (67%)/ Pembina (33%) / Empress II: IPF (100%)/ Empress V: Plains Midstream Canada ULC 5,927 1,381 23% 152 49 32% Spec C2/ C3+ Mix 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%)

Plains (35.5%)/ ExxonMobil, Shell, & Talisman (15.6%)/ Pembina (12.4%)/ ATCO Energy Solutions Ltd. 1,040 464 45% 14 11 82% Spec C2/ C3+ Mix 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%) ATCO Energy Solutions Ltd. 35 24 69% 2 1 69% Spec C2/ C3+ Mix ATCO Midstream (100%) AltaGas Ltd. 237 12 5% 13 7 54% C2+ Mix AltaGas (100%) 14,659 7,227 49% 526 289 55% 16,000 80% JOFFRE ETHANE EXTRACTION PLANT ATCO FORT SASKATCHEW AN 14,000 70% AMOCO ELLERSLIE 12,000 60% COCHRANE EXTRACTION PLANT ATCO MIDSTREAM EMPRESS (3) 10,000 50% PANCDN EMPRESS PETRO-CAN EMPRESS

8,000 40% %

AMOCO EMPRESS MMcf/d 6,000 30% Empress Empress Capacity 4,000 20% AB Straddle Plant Processing Capacity 2,000 10% AB Straddle Plant Processing Empress Utilization (%) - 0% Straddle Plants Processing Utilization (%) 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

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)

Total Canadian Fractionation Capacity 300 268 100% KFS Location, Type Capacity (kb/d) % of Total 95% 250 237 227 DFS 217 221 216 AB, Field Spec NGL Capacity 442 40% 209 90% AB, Fractionators 325 29% 196 190 192 194 200 RFS AB, Straddle Plants 180 16% 85% NE BC, Field Spec NGL Capacity 24 2% 150 80% % PFS Subtotal Western Canada 971 88% kb/d 75% 100 Total Ft. Sk. Frac. NGLs ON, Sarnia Fractionator 114 10% 70% NS, Point Tupper Plant 19 2% 50 Ft. Sk. Fractionation Cap. 65% Subtotal Central/ Eastern Canada 133 12% Utilization (%) - 60% 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 TOTAL CANADA 1,104 100% 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) Plains Midstream 114 77 68% Spec NGLs & C3/C4 Mix Redwater Fort Saskatchewan (RFS) Pembina Pipeline Corporation 69 57 82% C2, C3, C4, C5+ Dow Fort Saskatchewan (DFS) Dow Chemicals/ Keyera Corp. 66 45 69% C2, C3, C4, C5+ Keyera Fort Saskatchewan (KFS) Keyera Corp./ Plains Midstream 30 31 104% C3, C4, C5+ Williams Redwater Williams/ Pembina Pipeline Corporation 17 13 78% C2, C3, C4, C2=, C3=, C4=, Olefinic C5+ Subtotal Fort Saskatchewan 296 224 76%

Other Alberta GIBSON HARDISTY Gibson Energy ULC 4 2 54% C2, C3, C4, C5+ PLAINS BUCK CREEK FRAC PLANT Plains Midstream Canada ULC 20 1 4% C2, C3, C4, C5+ HIGH PRAIRIE FRACTIONATIO N PLANT Plains Midstream Canada ULC 5 3 73% C3, C4, C5+ STITTCO KEMP Stittco Energy Limited 0.2 0.2 100% C3, C4, C5+ Subtotal Other Alberta 29 7 23% Total Alberta 325 231 71%

Central/ Eastern Canada Sarnia Plains Midstream/ Pembina Pipeline Corporation 114 95 84% C3, iC4, nC4, C5+ Point Tupper (SOEP) Exxon Mobil 19 8 44% C3, C4, C5+ Total Central/ Eastern Canada 133 104 78%

TOTAL CANADA 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 19 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

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 13 Part II – Midstream and Downstream Infrastructure 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 TransportationI nfrastructure (top) and Distribution Companies/Areas (bottom)

Source: CEPA20 and CGA21

20 Canadian Energy Pipeline Association (CEPA): www.cepa.com 21 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 Also known as the Nova Gas Transmission Ltd. System (NGTL) 23 Connection through Trans-Quebec & Maritimes (TQM) pipeline system

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 15 Part II – Midstream and Downstream Infrastructure 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 17 Part II – Midstream and Downstream Infrastructure 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 Storage Facility Owner/ Operator Products Capacity (MMb) Raw Mix Pipelines to Ft. Saskatchewan Peace HVP System (NGLs) 76 C2+/ C3+ Ft. Saskatchewan (AB NGL Hub) Cochrane-Edmonton (Co-Ed) System 68 C3+ Fort Saskatchewan Keyera NGLs 11 Brazeau NGL Gathering System 57 C2+ Redwater Pembina Pipeline Corporation NGLs 8 Peace LVP System (Condensate) 52 C5+ (Includes Crude) Northern System 49 C2+/ C3+ Fort Saskatchewan Plains Midstream NGLs 4 Boreal 43 NGLs/ Olefins Mix Fort Saskatchewan Joint Venture Veresen Inc./ Plains Midstream C2 1 Bonnie Glen 33 C5+ (Includes Crude) Fort Saskatchewan Dow/ Keyera Corp. NGLs 1 Judy Creek 30 C3+ Total Raw Mix Pipelines Est. Capacity 408 Alberta Diluent Terminal (ADT) Keyera Corp. C5+ 0.3 Subtotal Ft. Saskatchewan 24 Petrochemical Feedstock Pipelines Alberta Ethane Gathering System (AEGS) 334 Spec C2 Ethylene Delivery System (EDS) 86 Ethylene Kerrobert, SK Joffre Feedstock Pipeline (JFP) 48 NGLs Kerrobert Pembina Pipeline Corporation/ Plains Midstream NGLs 3

NGL Export Pipelines Subtotal Saskatchewan 3 Enbridge Mainline (Lines 1/5)* 127 C3+ Mixes Kerrobert (to Enbridge) 124 C3+ Mixes Alliance Pipeline 93 NGLs in Gas Total Western Canada 26 Cochin Pipeline 71 Spec C3/ USMW E/P Mix Petroleum Transmission Company** 27 Spec C3/ C4 Ontario Total NGL Export Pipelines Est. Capacity 442 Sarnia Pembina Pipeline Corporation/ Plains Midstream Spec NGLs 6 NGL Import Pipelines Corunna Pembina Pipeline Corporation NGL Mix 5 Southern Lights/ Line 13 171 C5+ Mariner West (Late 2013/ Early 2014) 48 Spec C2 Sarnia Pembina Pipeline Corporation/ Plains Midstream NGL Mix 2 Vantage Pipeline (2014) 43 Spec C2 Total Ontario 13 UTOPIA Pipeline (2017-18)*** 59 Spec C2/ Spec C3 Total NGL Import Pipelines Est. Capacity 321 *Net of Kerrobert/ **CERI Estimate/ ***Announced TOTAL CANADA 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 27 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

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% Off-Gas SGL Mixes 400 90% BC NGL Mixes 350 80% 70% 300 Straddle Plants NGL Mixes (Exc. Empress) 60% 250 C5+/ Condensate

50% % kb/d 200 40% AB Field NGL Mixes 150 30% Pipeline Capacity to Ft. Sk. 100 20% Total Liquids to Ft. Sk. 50 10% - 0% Utilization (%) 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

80 100%

70 95% 60

50 90%

40 % kb/d 85% 30

20 BC Plants NGL Mixes AB Plants NGL Mixes 80% System Capacity 10 Total Utilization (%) - 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) 30 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)

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 19 Part II – Midstream and Downstream Infrastructure 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 33 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.

May 2014 20 Canadian Energy Research Institute

39 Enbridge’s Lines 1/5 transport an NGL mix (primarily C3/C4) 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 40 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

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 21 Part II – Midstream and Downstream Infrastructure 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 marketingoutlets .53

50 But also through rail cars, a means to transport crude oil which continues to gain market share 51 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-rail- terminal-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

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: AAR57

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 23 Part II – Midstream and Downstream Infrastructure Table 1.4: Large Canadian Midstream Companies NGL Rail Handling Facilities58 (top) and Rail Car Fleet59 (bottom) (2012)

Facility Onwer/ Operator Type Capacity (kb/d) Location Redwater Pembina Pipeline Corporation C5+ rail off load facility 75 AB NGL Hub Alberta Diluent Terminal (ADT) Keyera Corp. C5+ rail off load 50 AB NGL Hub Edmonton Terminal Keyera Corp. C3,C4, C5+ loading/ offloading 34 AB NGL Hub Rimbey Rail Terminal Keyera Corp. C3, C4, C5 loading 13 WCSB Gilby and Nevis Rail Terminals Keyera Corp. C3, C4, C5 loading 7 WCSB Sarnia/ St. Clair/ Windsor Pembina/ Plains C3, C4, C5 loading 45 Southern ON Total 225 Facility Onwer/ Operator Type # of Railcars Location NGLs Infrastructure Altagas Corp./ Petrogas NGLs Rail Cars 1,500 WCSB/ US NGLs Infrastructure Keyera Corp. NGLs Rail Cars 1,300 AB NGL Hub Redwater Rail Cars Pembina Pipeline Corporation NGLs Rail Cars 700 AB NGL Hub Empress/ Sarnia Rail Cars Pembina Pipeline Corporation NGLs Rail Cars 300 AB NGL Hub/ ON LPG Railcars Gibsons Energy NGLs Rail Cars 500 WCSB/ US Total 4,300 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) # of Upgrader Location Bitumen Capacity (kb/d) Location Refining Capacity (kb/d) Refineries Suncor Base + Millenium Ft. Mc Murray 440 Atlantic Canada 499 3 Syncrude Mildred Lake Ft. Mc Murray 407 Ontario 475 5 AOSP - Shell Scotford Ft. Saskatchewan 255 Alberta 451 3 Nexen Long Lake Ft. Mc Murray 72 Quebec 402 2 CNRL Horizon Ft. Mc Murray 141 BC & SK 304 5 Husky Lloydminster Lloydminster AB/ SK 96 Total Canada 2,130 18 Total Upgrading Capacity 1,411 Off-Gas Processing Plants

Plant Owner/ Operator Capacity (MMcf/d) Output Location Aux Sable Heartland Off-gas Plant Veresen/ Enbridge 20 MMcf/d C2, C3+, H2 AB Industrial Heartland Williams Ft. McMurray Off-gas Plant (Suncor) Williams 125 MMcf/d & ~18 kb/d NGLS/ Olefins Mix NGLS/ Olefins 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 end- users 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 25 Part II – Midstream and Downstream Infrastructure 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

Value Multiplier (x times) - 2 4 6 8 10 12 14 16 18 20

LDPE Film $2,246 19 HDPE Injection Molding $2,225 19 HDPE Blow Molding $2,202 18 LLDPE-Octene-1Film $2,154 18 LLDPE-Hexene-1Film $2,133 18 HDPE HMW Film $2,114 18 LLDPE-Butene-1Film $2,045 17 Propylene (Polymer Grade) $1,309 11 Ethylene $1,305 11

Gasoline $1,099 9 Product Kerosene $992 8 Furnace Oil $964 8 Pentanes Plus $900 8 Upgrading natural gas and NGLs to various Butanes $847 7 forms of plastics and consumer products adds Light Sweet Crude $843 7 significant incremental economic value Propane $407 3 Ethane $229 2 Natural Gas $120 1

0 500 1,000 1,500 2,000 2,500 $/ t Source: Data from ADOE, EIA, the Kent Group, and Dewitt & Company.63 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 end- use 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 ethyl- benzene 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 27 Part II – Midstream and Downstream Infrastructure Table 1.6: Canadian Petrochemical Plant Information (2012)

ALBERTA Plant Capacity Required Company Facility Location Main Product (kt/yr) Feedstock Feedstock (kb/d)

Ethylene Crackers (Olefins) NOVA Chemicals Ethylene 1 (E1) Joffre Complex, AB Ethylene 726 C2/ Some C3 45 NOVA Chemicals Ethylene 2 (E2) Joffre Complex, AB Ethylene 816 C2/ Some C3 51 NOVA Chemicals (50%)/ Dow Chemicals (50%) Ethylene 3 (E3) Joffre Complex, AB Ethylene 1,270 C2 79 Dow Chemicals Dow Fort Saskatchewan (LHC1) Fort Saskatchewan, AB Ethylene 1,285 C2 80 Total Ethylene Crackers 4,097 255

Aromatics Plants Shell Canada Shell Scotford Refinery Scotford, AB Benzene 370 Crude Oil n/a Total Aromatics 370

Ethylene Derivatives

Required Feedstock (kt/yr) Polyethylene and Similar Products NOVA Chemicals Polyethylene 1 (PE1) Joffre Complex, AB LLDPE 671 Ethylene 678 NOVA Chemicals Polyethylene 2 (PE2) Joffre Complex, AB LLDPE & HDPE 431 Ethylene 435 INEOS Oligomers Joffre Linear Alpha Olefins (LAO) Plant Joffre Complex, AB LAO 250 Ethylene 253 Dow Chemicals Prentiss PE Red Deer, AB LLDPE 500 Ethylene 505 Dow Chemicals Fort Saskatchewan PE Fort Saskatchewan, AB LLDPE 850 Ethylene 859 Celanese (AT Plastics) Edmonton EVA Manufacturing Plant Edmonton, AB LDPE, EVA 143 Ethylene 61 Total 2,845 2,790

Ethylene Glycol ME Global (50% owned by Dow Chemicals) Prentiss I Ethylene Oxide/ Ethylene Glycol (EO/EG) Plant Red Deer, AB MEG 310 Ethylene 179 ME Global (50% owned by Dow Chemicals) Prentiss II EO/EG Plant Red Deer, AB MEG 285 Ethylene 165 ME Global (50% owned by Dow Chemicals) Fort Saskatchewan (FS) 1EO/ EG Plant Fort Saskatchewan, AB EO/EG 350 Ethylene 202 Shell Chemicals Scotford Manufacturing Monoethylene Glycol (MEG) Shell Chemicals Canada Ltd. Plant Scotford, AB MEG 450 Ethylene 260 Total 1,395 806

Styrene Monomer Shell Chemicals Canada Ltd. Shell Chemicals Scotford Manufacturing Styrene Monomer (SM) Plant Scotford, AB SM 450 Ethylene 121 Benzene 365 Total 450 486

Other Facilities Keyera Corp. Alberta EnviroFuels (AEF) Edmonton, AB Iso-octane 521 Field Butanes (f-C4) n/a Williams Canada Redwater Fractionator/ Propylene Plant Redwater, AB PGP 68 SGLs Mix n/a Total 589

ONTARIO

Plant Required Company Facility Location Main Product Capacity Feedstock Feedstock (kb/d) (kt/yr)

Ethylene Crackers (Olefins) NOVA Chemicals Corunna, Ethylene Corunna, ON Ethylene 839 C2,C3,C4,C5+ 67 Imperial Oil Products & Chemicals Imperial Sarnia Sarnia, ON Ethylene 300 C2,C3,C4,C5+ 23 Total Ethylene Crackers 1,139 90

Aromatics Plants Benzene Imperial Oil Imperial Sarnia Corunna, ON Benzene 110 Crude Oil/ NGLs n/a Nova Chemicals Corunna, Ethylene Sarnia, ON Benzene 120 Crude Oil/ NGLs n/a Shell Shell Sarnia Sarnia, ON Benzene 60 Crude Oil n/a Sunoco Chemicals (Suncor) Suncor Sarnia Sarnia, ON Benzene 50 Crude Oil n/a Total Benzene 340

Toluene Imperial Oil Imperial Sarnia Sarnia, ON Toluene 85 Crude Oil/ NGLs n/a Shell Shell Sarnia Sarnia, ON Toluene 130 Crude Oil n/a Sunoco Chemicals (Suncor) Suncor Sarnia Sarnia, ON Toluene 207 Crude Oil n/a Total Toluene 422

Required Feedstock (kt/yr) Ethylene Derivatives Polyethylene and Similar Products NOVA Chemicals St. Clair River, Corunna, ON PE Corunna, ON HDPE 204 Ethylene 194 NOVA Chemicals Mooretown, ON PE Mooretown, ON HDPE 211 Ethylene 200 NOVA Chemicals Mooretown, ON PE Mooretown, ON LDPE 170 Ethylene 161 Imperial Oil Products & Chemicals Sarnia PE Sarnia, ON HDPE 470 Ethylene 446 Total 1,055 1,002

Styrene Monomer Styrolution Styrolution Sarnia Production Site Sarnia, ON SM 431 Ethylene 116 Benzene 339 Total 431 455

Other Facilities Mixed C4's, Butylene, Butadiene, Styrene, Lanxess Inc. Sarnia Site Sarnia, ON Butyl Rubber 150 Other n/a Total 150

May 2014 28 Canadian Energy Research Institute

QUEBEC Plant Required Company Facility Location Main Product Capacity Feedstock Feedstock (kt/yr) (kt/yr)

Aromatics Plants Benzene Suncor Suncor Refinery/ Petrochemicals Montreal, QC Benzene 350 Crude Oil n/a Total 350

Toluene Suncor Suncor Refinery/ Petrochemicals Montreal, QC Toluene 240 Crude Oil n/a Total 240

Other Facilities Aromatics Derivatives p-Xylene ParaChem Chemicals (Suncor) Montreal Site Montreal, QC p-Xylene 350 Benzene & Toluene n/a Total 350

Xylene/PTA Derivatives Interquisa Canada (CEPSA Chimie) Montreal Site Montreal, QC PTA 500 p-Xylene 350 Selenis Montreal Site Montreal, QC PET 150 PTA 345

Sources: Data from AED,64 AIEM,65 BMI,66 CERI research,67 MEI,68 Industry data, OGJ data,69 and Sarnia-Lambton Economic Partnership.70 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/Business- Monitor-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-ethylene- from.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 29 Part II – Midstream and Downstream Infrastructure Table 1.7: Major Petrochemical Clusters in Canada, Summary

ALBERTA

From: Petrochemical Plants To: Derivative Plants Feedstock Type Capacity (kt/yr) Type Req. (kt/yr)

Olefins Plants 68% 2,790 Polyethylene/ Similar Plants Ethylene Crackers 4,097 20% 806 MEG Plants 3% 121 SM Plant Total 91% 3,717 Total Derivative Plants Balance 9% 380 Excess Capacity

Aromatics Plants Benzene 370 99% 365 SM Plant Total 99% 365 Total Derivative Plants Gasoline Blend, Industrial 6 Balance 1% Chemicals, and Solvents

ONTARIO

From: Petrochemical Plants To: Derivative Plants Feedstock Type Capacity (kt/yr) Req. (kt/yr) Type

Olefins Plants 88% 1,002 Polyethylene/ Similar Plants Ethylene Crackers 1,139 10% 116 SM Plant Total 98% 1,118 Total Derivative Plants Balance 2% 21 Excess Capacity

Aromatics Plants Benzene 340 100% 339 SM Plant Total 100% 339 Total Derivative Plants Gasoline Blend, Industrial Balance 0% 1 Chemicals, and Solvents

Gasoline Blend, Industrial Toluene 422 422 100% Chemicals, and Solvents Total 100% 422 Total Derivative Plants Balance 0% -

QUEBEC

From: Petrochemical Plants To: Derivative Plants Feedstock Type Capacity (kt/yr) Type Req. (kt/yr)

Aromatics Plants Benzene Derivatives (Including p-X Benzene 350 100% 350 plant) & Refinery Feedstocks Total 100% 350 Total Derivative Plants Balance 0% -

Toluene Derivatives (Including p-X Toluene 240 100% 240 plant) & Refinery Feedstocks Total 100% 240 Total Derivative Plants Balance 0% -

CANADA

From: Petrochemical Plants To: Derivative Plants Feedstock Type Capacity (kt/yr) Type Req. (kt/yr)

Olefins Plants 72% 3,791 Polyethylene/ Similar Plants Ethylene Crackers 5,236 15% 806 MEG Plants 5% 237 SM Plants Total 92% 4,834 Total Derivative Plants Balance 8% 402 Excess Capacity

Aromatics Plants Benzene & Toluene SM Plants Plants 1,722 41% 704 Total 41% 704 Total Derivative Plants Other Benzene & Toluene Derivatives (Including p-X plant) & Balance 59% 1,018 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 75 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

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 31 Part II – Midstream and Downstream Infrastructure 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 off- gas 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 Butylene [2901.23] 8,000 7,443 7,478 7,497 7,607 18,000 7,189 Butadiene [2901.24.10] 6,861 6,680 6,762 6,752 16,000 7,000 3% 3% 6,134 4% 14,000 Toluene [2902.3] 4% 6,000 12,000 8% 5,000 Xylene (Including PET Equivalent) 10,000 kt/yr 4,000 Benzene [2902.2] 9% 8,000 MMlbs/yr 3,000 6,000 Propylene, all grades [2901.22] 69% 2,000 4,000 Ethylene (PE Based Estimate) 1,000 2,000 Total (kt/yr) - - 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Source: Data from Industry Canada,77 Statistics Canada,78 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 co- product 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 co- product derivative users’ operations.

79 This is discussed in more detail in Part IV of the NGLs Update 80 ICIS, Canada Petromont closure “a major loss”: http://www.icis.com/Articles/2008/02/13/9100564/canada-petromont- closure-a-major-loss.html 81 There is an 86% correlation between gasoline production and benzene production levels (2002 – 2012)

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 33 Part II – Midstream and Downstream Infrastructure 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 8,143 7,729 8,000 7,460 7,519 7,594 7,187 7,076 6,826 6,827 6,875 7,000 6,251 6,000

5,000

kt/yr 4,000

3,000 Other Refineries/ Aromatics Plants 2,000 Propane Ethylene Crackers Total CERI Estimates StatsCan Based Totals 1,000

- 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

6,000 94%

5,106 4,992 5,054 92% 4,740 4,756 5,000 4,602 4,595 4,681 4,691 4,596 4,428 90% 4,000 88%

3,000 86% % kt/yr 84% 2,000

Heavy Feeds Light Naphthas/ LPGs 82% 1,000 Butane Propane Ethane/ Propane Mix Ethane 80% Estimated Ethylene Production Reported Ethylene Production (StatsCAN) Ethylene Cracking Capacity (kt/yr) Cracking Capacity Utilization (%) - 78% 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 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 Canadian Energy Research Institute

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 35 Part II – Midstream and Downstream Infrastructure 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)

Source: EIA85

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 ratef o about 65 percent (see Table 2.1).

83Energy 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 PADD I - East Coast Regency Field Services LLC PADD II - Midwest Anadarko Petroleum Corp Williams Field Services PADD III - Gulf Coast Plains Gas Solutions, LLC PADD IV - Rockies Enbridge Pipelines (Texas Gathering) L.P. PADD V - West Coast 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 - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 MMcf/d Source: Argus,87 CERI research, EIA,88 Industry data,89 PennWell MAPSearch, Platts,90 and Oil & Gas Journal.91 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 37 Part II – Midstream and Downstream Infrastructure 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 Kentucky 2011 - 16 Total US Additions: 15,178 MMcf/d 6,000 PADD III: 5,625 MMcf/d (39%) Oklahoma PADD I: 5,560 MMcf/d (38%) North Dakota 5,000 PADD II: 3,993 MMcf/d (23%) Ohio 4,000 Pennsylvania West Virginia

MMcf/d 3,000 Texas 2,000 Total PADD II

1,000 Total PADD I 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

79,378 79,978

77,878 75,083

90,000 68,643

67,987

67,038

66,828 63,533

80,000 59,810

56,588 53,736 70,000 51,177 60,000 50,000

MMcf/d 40,000 PADD V 30,000 PADD I PADD II 20,000 PADD IV PADD III 10,000 Total US - 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 Ohio 8,765 9,000 8,365 Pennsylvania 8,000 West Virginia 6,965 7,000 Marcellus/ Utica 5,845 6,000 5,000

MMcf/d 4,000 3,000 2,500 2,000 1,462 866 1,000 391 414 438 463 490 519 - 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 39 Part II – Midstream and Downstream Infrastructure 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% California 2,196 2012 Total US Capacity: 3,079 kb/d Utah 70% Colorado 2,000 60% West Virginia Pennsylvania Kentucky 1,500 50% Michigan 40% Illinois kb/d Oklahoma 1,000 %of Total 716 30% Kansas New Mexico 20% 500 Louisiana Texas 122 10% 34 12 PADD Total - 0% % of Total PADD I - East PADD II - Midwest PADD III - Gulf PADD IV - Rockies PADD V- West Coast Coast 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 PADD I - East Coast CMS Marysville Gas Liquids Co. ConocoPhillips PADD II - Midwest MarkWest PADD III - Gulf Coast Dominion Transmission PADD IV - Rockies Plains All American (LPG Services) SouthCross Energy PADD I - West Coast Kinder Morgan Energy Partners Valero Energy Energy Transfer Partners Tembec Company - 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 Ohio 900 PADD III: 2,295 kb/d (70%) North Dakota 800 PADD I: 556 kb/d (17%) PADD II: 448 kb/d (13%) Kansas 700 Illinois 600 West Virginia

500 Pennsylvania kb/d 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) PADD I - East Coast Formosa Hydrocarbons Company PADD II - Midwest Equistar Chemical (LyondellBasell)/ TexStar Midstream PADD III - Gulf Coast 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 - 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 41 Part II – Midstream and Downstream Infrastructure Figure 2.7: US Fractionation Capacity by Region (kb/d) (2009 – 2016)

6,000 5,625 6,000 California Utah 5,035 Colorado Pennsylvania 5,000 5,000 4,430 West Virginia Kentucky 3,942 Michigan 4,000 4,000 North Dakota 3,079 Ohio Illinois 3,000 2,750 3,000 Oklahoma

kb/d 2,425 2,264 Kansas New Mexico 2,000 2,000 Louisiana Texas PADD IV 1,000 1,000 PADD V PADD I PADD II PADD III - - Total US 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)

900 848 Ohio 808 800 Pennsylvania West Virginia Marcellus/ Utica De-C2 Capacity 700 620 Total Marcellus/ Utica Fractionation Capacity 600

500 422

kb/d 400

300

200 122 92 100 19 19 - 2009 2010 2011 2012 2013 2014 2015 2016

400 MarkWest Utica-Cadiz (Harrison Co.) -Ohio-New De-C2 MarkWest Utica-Noble Co., Seneca Complex -Ohio-New De-C2 365 Williams Partners (Ohio Valley Midstream)-Oak Grove (Marshall) -West Virginia-New De-C2 350 MarkWest Liberty Midstream-Sherwood -West Virginia-New De-C2 325 MarkWest Liberty Midstream-Mobley -West Virginia-New De-C2 Caiman Eastern Midstream (Williams Partners)-Taylor (Marshall Co.) -West Virginia-New De-C2 (2) 300 Caiman Eastern Midstream (Williams Partners)-Fort Beeler, Cameron -West Virginia-New De-C2 (1) MarkWest Liberty Midstream-Majorsville -West Virginia-De-C2 2 MarkWest Liberty Midstream-Majorsville -West Virginia-De-C2 1 249 250 MarkWest Utica-Bluestone, Butler Co. (Keystone) -Pennsylvania-De-C2 MarkWest Liberty Partners-Houston -Pennsylvania-De-C2 Marcellus/ Utica De-C2 Capacity

200 kb/d

150 106 100

50 - - - - 0 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

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 43 Part II – Midstream and Downstream Infrastructure

Figure 2.9: Major NGL Pipeline Corridors and Fractionation Centers in the United States Bakken NGL Bakken

SARNIA

CHICAGO System Buckeye System Mariner East East Unity HOUSTON Cornerstone

CONWAY

NGL HUB

Existing NGL Mix Pipeline

Existing Spec NGL Pipeline

Proposed NGL Mix Pipeline

Proposed Spec NGL

Emerging Hub

MT. BELVIEU

Source: Background image from EIA,93 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

NGL Mix Pipelines INTER-PADD SYSTEMS Flow System Origin Destination Region Capacity (kb/d) Expansion (kb/d) Total Capacity (kb/d) Expected Completion Owners PADDs I/II --> III Bluegrass Pennsylvania, West Virginia, Ohio Lake Charles, Louisiana (Moss Lake) 200 - 200 2016 Boardwalk/ Williams JV

Kinder Morgan/MarkWest Energy Utica Marcellus Texas PADDs I/II --> III Pennsylvania, West Virginia, Ohio Mt. Belvieu, Texas 200 - 200 2016 Partners (MarkWest and Energy Pipeline (UMTP) Minerals Group JV)

Subtotal PADDs I/II --> III* US Gulf Coast (USGC) 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

DCP Midstream (Phillips 66/ Spectra PADD II --> III Southern Hills Kansas/Oklahoma Mt. Belvieu, Texas 175 - 175 2013 Energy)

Mid-America Pipeline (MAPL) PADD II --> III System: Conway South Conway, Kansas Hobbs, New Mexico/ Texas border 75 - 75 Operating Enterprise Product Partners Segment Subtotal PADD II --> III USGC 983

DCP Midstream Partners/Anadarko PADD IV --> III Front Range DJ Basin, Colorado (Weld County) Skelly Town, Texas 150 - 150 2014 Petroleum Corp./Enterprise Product Partners JV

MAPL System: Rocky Rocky Mountain overthrust/San Juan PADD IV --> III PADD III (Hobbs: New Mexico/ Texas border) 275 85 360 2014 Enterprise Product Partners Mountain Segment (RMGS) Basin Phillips 66/Chevron Phillips (CP) PADD IV --> III Powder River/Mextex Sage Creek, Wyoming/Artersia, NM Borger, Texas/Benedum Texas 70 - 70 Operating Chemicals Subtotal PADD IV --> III USGC 580

TOTAL PADDs I, II, & IV --> III USGC 1,963

(Opal) Wyoming (Greater Green River PADD IV --> II Overland Pass PADD II (Bushton-Conway, Kansas) 195 60 255 2013 Oneok Partners/ Williams JV Basin), Colorado (DJ Basin, Piceance) PADD IV --> II Wattenberg DJ Basin PADD II (Bushton-Conway, Kansas) 25 - 25 Operating DCP Midstream Subtotal PADD IV --> II Conway, Kansas 280

MAJOR INTRA-PADD SYSTEMS Flow System Origin Destination Region Capacity (kb/d) Expansion (kb/d) Total Capacity (kb/d) Expected Completion Owners DCP Midstream (Phillips 66/ Spectra PADD II Chrisholm Kingfisher, Oklahoma Conway, Kansas 42 - 42 Operating Energy)

Eagle Ford (SE Texas)/ Permian (W DCP Midstream (Phillips 66/ Spectra PADD III Sand Hills Mt. Belvieu, Texas 200 - 200 2013 Texas) Energy)

DCP Midstream Partners/ Enbridge PADD III Texas Express Pipeline Skellytown (Carson Co.) Mt. Belvieu, Texas 280 - 280 2013 Energy Partners/ Anadarko Petroleum Corp./Enterprise Product Partners JV

PADD III Black Lake NW Louisiana/ SE Texas Mt. Belvieu, Texas 40 - 40 Operating DCP Midstream Seabreeze --> Wilbreeze --> Sand Hills --> Mt. PADD III Seabreeze/Wilbreeze SE Texas (Eagle Ford) 50 - 50 Operating DCP Midstream Belvieu, Texas

MAPL system: RMGS (Rockies) and PADD III Seminole Pipeline Conway South (Midwest) Segment/ Mt. Belvieu, Texas 260 - 260 Operating Enterprise Product Partners Permian basin (West Texas)

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

LoneStar NGL LLC (Energy Transfer PADD III West Texas Gateway Permian/Delaware/Eagle Ford Basins Mt. Belvieu, Texas 209 - 209 2012 Partners LP/Regency Energy Partners LP) Eagle Ford/ Yoakum NGL PADD III Eagle Ford Basin Mt. Belvieu, Texas 310 140 450 2013 Enterprise Product Partners Pipeline

PADD III Cajun-Sibon Louisiana Mt. Belvieu, Texas 70 - 70 2013 Crosstex Energy LP

PADD III TX Panhandle Y1/Y2 Sherman, Texas Borger, Texas 73 - 73 Operating Phillips 66 PADD III Line EZ Rankin, Texas Sweeney, Texas 101 - 101 Operating Phillips 66 PADD III Sweeney EP Mt. Belvieu, Texas Sweeney, Texas 40 - 40 Operating Phillips 66/CP Chemicals Atlas Pipeline/ Chevron Pipeline PADD III West Texas LPG NGL Line New Mexico/Texas Mt. Belvieu, Texas 245 - 245 Operating Company

PADD III West Texas System West Texas (Permian/Barnett Basins) Mt. Belvieu, Texas 140 - 140 Operating LoneStar NGL LLC

West Texas (Permian/Barnnet)/SE Texas PADD III Justice System Mt. Belvieu, Texas 260 80 340 2013 LoneStar NGL LLC (Eagle Ford Basin) PADD III Mariner South Mt. Belvieu, Texas Nederland, Texas 200 - 200 2015 LoneStar NGL LLC/Sunoco Logistics JV Subtotal PADD III US Gulf Coast 2,643

PADD IV Bakken NGL Bakken play (Montana/ North Dakota) Colorado (Overland Pass System) 60 75 135 2014 Oneok Partners

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 45 Part II – Midstream and Downstream Infrastructure

SPEC PRODUCT PIPELINES ETHANE/PROPANE Flow System Origin Destination Region Capacity (kb/d) Expansion (kb/d) Total Capacity (kb/d) Expected Completion Owners

Applachia-to-Texas-Express PADDs I/II --> III Pennsylvania, West Virginia, Ohio Mont Belvieu, Texas 125 65 190 2014 Enterprise Product Partners (ATEX)

Sunoco Logistics/ MarkWest Liberty Midstream & Resources, LLC JV PADDs I/II --> Ontario Mariner West Pennsylvania, West Virginia, Ohio Sarnia, Ontario 50 - 50 2014 (MarkWest Energy Partners/Energy & Minerals Group)

Sunoco Logistics/ MarkWest Liberty PADDs I/II --> Export Terminal Mariner East I Pennsylvania, West Virginia, Ohio Marcus Hook, Pennsylvania 70 - 70 2014 Midstream & Resources, LLC JV Sunoco Logistics/ MarkWest Liberty PADDs I/II --> Export Terminal Mariner East II Pennsylvania, West Virginia, Ohio Marcus Hook, Pennsylvania 70 - 70 2016 Midstream & Resources, LLC JV

Utica-to-Ontario-Pipeline PADDs I/II --> Ontario Pennsylvania, West Virginia, Ohio Sarnia, Ontario 50 - 50 2017 Kinder Morgan Access (UTOPIA)

Alberta/Saskatchewan Empress border: PADD II --> Alberta Vantage North Dakota connection to Alberta Ethane Gathering System 40 - 40 2014 Mistral Midstream (AEGS)

MAPL: Conway North PADD II Conway, Kansas Upper Midwest (Chicago area) 80 - 80 Operating Enterprise Product Partners Segment

MAPL: Ethane-Propane (E/P) PADD II Conway, Kansas Petrochemical plants in Iowa and Illinois 70 - 70 Operating Enterprise Product Partners Mix Segment PADD III AEGIS Mt. Belvieu, Texas Petrochemical plants along the USGC (TX-LA) 425 - 425 2014 Enterprise Product Partners

LPG: PROPANE/BUTANES PADD III --> II Blue Line Borger, TX Upper Midwest (St. Louis, ILL) 29 - 29 Operating Phillips 66 Southeastern US (Alabama, Georgia, Louisiana, Mt. Belvieu/ South Louisiana/ PADD III --> I Dixie Mississippi, North Carolina, South Carolina, and 160 - 160 Operating Enterprise Product Partners Mississippi Texas) TEPPCO: Texas --> Seymour, Indiana --> Chicago, Upper Texas Gulf Coast/Beaumont, Illinois/Lima, Ohio/Selkirk, New PADD III --> II & I TEPPCO/ Centennial 100 - 100 Operating Enterprise Product Partners Texas York/Philadelphia, Pennsylvania. Centennial: Bourbon, Illinois PADD II North System Kansas <--> Illinois Kansas <--> Illinois 134 - 134 Operating Oneok Partners Kansas NGL hub (Conway) & Area Iowa, Kansas, Nebraska, North Dakota, South PADD II East System 100 - 150 Operating NuStar Energy LP Refineries Dakota PADD II Conway to Wichita Conway, Kansas Whichita, Kansas 38 - 38 Operating Phillips 66 PADD II Medford Ponca City, Oklahoma Medford, Oklahoma 60 - 60 Operating Phillips 66 PADD III Sweeney Propane/Butane Clemens, Texas Pasadena, Texas 31 - 31 Operating Phillips 66/CP Chemicals

DILUENT: NATURAL GASOLINE/NAPHTHA/CONDENSATE

Harvest Pipeline Company/NiSouce PADD I/II --> II Unity Pipeline Kensigton, Ohio Griffth, Indiana (Explorer pipeline) 60 - 60 2015 Midstream Services LLC/Somerset Gas Transmission Company, LLC JV

MPLX (Marathon Petroleum Energy PADD I/II --> II Cornerstone Cadiz, Ohio Marathon's Canton, Ohio Refinery 40 - 40 2016 Logistics)

PADD III --> II Explorer Houston/Port Arthur Texas Upper Midwest (Chicago area) 350 - 350 Operating Explorer Pipeline Consortium

Plains Midstream/Marathon PADD III --> II Capline Louisiana Upper Midwest (Chicago area) 1,000 - 1,000 Operating Petroleum/ Others

TEPPCO: Texas --> Seymour, Indiana --> Chicago, Upper Texas Gulf Coast/Beaumont, Illinois/Lima, Ohio/Selkirk, New PADD III --> II TEPPCO 500 - 500 Operating Enterprise Product Partners Texas York/Philadelphia, Pennsylvania. Centennial: Bourbon, Illinois PADD II --> AB Southern Lights Manhattan, Illinois Edmonton, Alberta 180 95 275 2015 Enbridge

PADD II --> AB Cochin Kanakee Co., Illinois Fort Saskatchewan, Alberta 95 - 95 2014 Kinder Morgan

* 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 46 Canadian Energy Research Institute

Table 2.3: US Ethylene Cracking Capacity by Region/Company (kt/yr) and EstimatedF eedstock Requirements (kb/d), 2012 Capacity Capacity Location % of Total Company % of Total (kt/yr) (kt/yr) PADD III - Gulf Coast 26,782 96% Equistar Chemicals LP (LyondellBasell) 4,880 17% Texas 19,923 71% Port Arthur, TX 2,350 8% ExxonMobil Chemicals Co. 4,090 15% Chocolate Bayou, TX 2,296 8% Dow Chemical Co. 3,900 14% Baytown, TX 2,197 8% Chevron Phillips Chemical Co. LP 3,555 13% Sweeny, TX 1,865 7% Shell Chemicals Corp. 2,630 9% 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% Point Comfort, TX 1,541 6% Deer Park, TX 1,179 4% Westlake Petrochemicals Corp. 1,293 5% Corpus Christi, TX 922 3% BASF Fina Petrochemicals 860 3% Cedar Bayou, TX 835 3% Beaumont, TX 816 3% Eastman Chemical Co. 781 3% LaPorte, TX 789 3% DuPont 680 2% Longview, TX 781 3% Flint Hills Corp. 635 2% Orange, TX 680 2% Williams Olefins 612 2% Port Neches, TX 180 1% Sasol North America Inc. 472 2% Houston, TX 102 0% Hunstman Corp. 180 1% Louisiana 6,859 24% Lake Charles, LA 1,561 6% Javelina Co. 151 1% Norco, LA 1,451 5% Total 28,012 100% Plaquemine, LA 1,260 4% Feedstock Capacity kb/d % of Total Taft, LA 1,000 4% Baton Rouge, LA 975 3% Ethane 1,061 54% Geismar, LA 612 2% Propane 391 20% PADD II - Midwest 1,230 4% Butane 73 4% Illinois 550 2% Morris, ILL 550 2% Naphtha 317 16% Iowa 476 2% Gas Oil 80 4% Clinton, IO 476 2% Kentucky 204 1% Other 56 3% Calvert City, KY 204 1% Total 1,977 100% US Total 28,012 100%

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 over- supplying 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 47 Part II – Midstream and Downstream Infrastructure Table 2.4: US Petrochemical Facility Expansions and New Constructions

Company Plant Type 2012 2013 2014 2015 2016 2017 2018 2019 2020

Dow Chemical Co. Taft 2, LA (Hahnville) Re-start 410 ------Westlake Petrochemicals Corp. Lake Charles #1, LA Expansion - 110 - 110 - - - - - BASF Fina Petrochemicals Port Arthur, TX Revamp/ Expansion - 344 86 ------Williams Olefins Geismar, LA Expansion - - 272 ------INEOS Olefins and Polymers USA Chocolate Bayou, TX Expansion - - 115 ------Westlake Petrochemicals Corp. Calvert City, KY Feedstock Conversion (C3 --> C2) & Expansion - - 286 ------

Equistar Chemicals LP (LyondellBasell) LaPorte, TX Expansion - - 375 ------Dow Chemical Co. Plaquemine (LHC 3), LA Feedstock Conversion (C4/C5 --> C2) - - 222 ------

Dow Chemical Co. Freeport (LHC 7), TX Expansion - - 278 ------Chevron Phillips Chemical Co. LP Sweeny, TX Expansion - - 91 ------Equistar Chemicals LP (LyondellBasell) Channelview, TX Expansion - - - 113 - - - - - Equistar Chemicals LP (LyondellBasell) Corpus Christi, TX Expansion - - - 363 - - - - - ExxonMobil Chemicals Co. Baytown, TX New Build (Brownfield) - - - - 1,500 - - - - Chevron Phillips Chemical Co. LP Cedar Bayou, TX New Build (Brownfield) - - - - - 1,500 - - - Dow Chemical Co. Freeport (LHC 9), TX New Build (Brownfield) - - - - - 1,500 - - - Formosa Plastics Corp. USA Point Comfort, TX New Build (Brownfield) - - - - - 900 - - - Sasol North America Inc. Lake Charles, LA New Build (Brownfield) ------1,500 - - OxyChem/MexiChem Ingleside, TX New Build (Greenfield) ------555 - - Shell Chemicals Corp. Monaca, PA New Build (Greenfield) ------1,500 - Aither Chemicals Marcellus/Utica New Build (Greenfield) ------300 - Axiall Corp./Lotte Chemical Lousiana New Build (Greenfield) ------1,000 - Braskem/Odebrecht (ASCENT) Parkersburg, WV New Build (Greenfield) ------1,500 Indorama Ventures Ltd. US Gulf Coast New Build (Greenfield) ------1,500 Total New Capacity (kt/yr) 410 454 1,724 586 1,500 3,900 2,055 2,800 3,000 Required Ethane Feedstock (kb/d) 26 28 107 37 93 243 128 174 187

Source: Argus, CERI research, EIA, ICIS,94 Industry data, PennWell MAPSearch, Platts,95 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-capacity- by-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 48 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 49 Part II – Midstream and Downstream Infrastructure 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 50 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 Keyera Energy Ltd. DEVON CANADA Devon Canada 9% 9% HUSKY OIL OPERATIONS LIMITED Canadian Natural Resources Limited 6% SHELL CANADA ENERGY 29% 9% ConocoPhillips Canada (BRC) Partnership CONOCOPHILLIPS CANADA (BRC) PARTNERSHIP Shell Canada Energy 6% 38% Husky Oil Operations Limited CENOVUS ENERGY INC. 8% SemCAMS ULC 5% ENCANA CORPORATION APACHE CANADA LTD. Encana Corporation 2% 7% 5% TAQA NORTH LTD. AltaGas Ltd. 2% Talisman Energy Inc. PENN WEST PETROLEUM LTD. 3% 6% 5% Suncor Energy Resources Partnership BONAVISTA ENERGY CORPORATION 3% 2% 5% 3% 5% 2% 3% Peyto Exploration & Development Corp. 2%3% 3% SUNCOR ENERGY RESOURCES PARTNERSHIP 4% 4% 3% 3% 3% 4% Pembina Gas Services Ltd. NISKA GAS STORAGE CANADA ULC Apache Canada Ltd. PEYTO EXPLORATION & DEVELOPMENT CORP. Top 15 = 7,361 MMcf/d (71% of Total) Cenovus Energy Inc. Top 15 = 7,550 MMcf/d (62% of Total) PENGROWTH ENERGY CORPORATION Other (467) = 4,713 MMcf/d (38%) Other (100) = 2,945 MMcf/d (29%) Other (100) Total (482) = 12,263 MMcf/d Other (467) Total (115) = 10,306 MMcf/d

Inter Pipeline Extraction Ltd. Keyera Energy Ltd. AltaGas Ltd. Pembina NGL Corporation 10% 7% 1%1% 15% 18% Devon Canada 1%1% Plains Midstream Canada ULC 1% Keyera Energy Ltd. 2% Inter Pipeline Extraction Ltd. 9% 3% Plains Midstream Canada ULC Dow Chemical Canada ULC 2% Husky Oil Operations Limited 7% Spectra Energy Empress Management Inc. 3% 13% 3% 9% 1195714 Alberta Ltd. AltaGas Ltd.

3% ConocoPhillips Canada (BRC) Partnership 8% 1195714 Alberta Ltd. Pengrowth Energy Corporation Shell Canada Energy 4% 8% Canadian Natural Resources Limited 11% Canadian Natural Resources Limited 4% 9% SemCAMS ULC ATCO Midstream Ltd. 4% 7% ATCO Midstream Ltd. Husky Oil Operations Limited 5% 10% 11% 5% 6% Talisman Energy Inc. Suncor Energy Resources Partnership Shell Canada Energy SemCAMS ULC Top 15 = 202 kb/d (82% of Total) Penn West Petroleum Ltd. Top 15 = 425 kb/d (93% of Total) ConocoPhillips Canada (BRC) Partnership NGLs Mix Spec NGLs Other (87) = 45 kb/d (18%) Other (87) = 30 kb/d (7%) Other (87) Total (102) = 247 kb/d Total (107) = 455 kb/d

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 51 Part II – Midstream and Downstream Infrastructure 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

WESTCOAST TRANSMISSION COMPANY LIMITED 1% 4% 1%1%1% SPECTRA ENERGY MIDSTREAM CORPORATION 2% 3% VERESEN ENERGY INFRASTRUCTURE INC. 4% SHELL CANADA LIMITED

4% MURPHY OIL COMPANY LTD. 42% CONOCOPHILLIPS CANADA OPERATIONS LTD. 5% CANADIAN NATURAL RESOURCES LIMITED ENCANA CORPORATION 5% ARC RESOURCES LTD.

6% TALISMAN ENERGY INC. TOURMALINE OIL CORP. 6% PENN WEST PETROLEUM LTD. 6% 8% KEYERA ENERGY LTD. AUX SABLE CANADA LTD. Top 15 = 3,627 MMcf/d (96% of Total) ALTAGAS LTD. Other (16) = 147 MMcf/d (4%) Other (16) Total (31) = 3,773 MMcf/d

ALTAGAS HOLDINGS INC. 1%1%1%0%1% 2%2% WESTCOAST TRANSMISSION COMPANY LIMITED 2% 2% 3% SPECTRA ENERGY MIDSTREAM CORPORATION 3% CONOCOPHILLIPS CANADA OPERATIONS LTD. CANADIAN NATURAL RESOURCES LIMITED 6% ARC RESOURCES LTD. TOURMALINE OIL CORP. 52% 8% CANBRIAM ENERGY INC. SHELL CANADA LIMITED

8% AUX SABLE CANADA LTD. KEYERA ENERGY LTD. 10% Husky Energy VERESEN ENERGY INFRASTRUCTURE INC. Imperial Oil Top 15 = 48 kb/d (99% of Total) NuVista Energy Other (10) = 1 kb/d (1%) Total (25) = 49 kb/d

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 52 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 98 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/Dcom- UnitedStates/Local%20Assets/Documents/Energy_us_er/us_er_RiseOfTheMidstream_Nov2013.pdf

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 53 Part II – Midstream and Downstream Infrastructure 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 Oilfield Services Downstream Upstream

Source: CERI based on PWC107

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-term- liquids-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/oil- gas-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 54 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 55 Part II – Midstream and Downstream Infrastructure Table 3.1: Recent Gas Processing/NGL Infrastructure Investments in Western Canada ($MM) (2011 – 2016)

PRODUCER-OWNED MIDSTREAM DIVESTITURES Company Plant Costs ($MM) Capacity (MMcf/d) $MM/ MMcf/d Transaction Date Type Location Notes Cutbank Complex (near Grand Pembina Pipeline Corporation Cutbank Complex (Kawka, Cutbank, and Musreau) $ 330 425 $ 0.8 2011 Shallow/ Deep-cut (Musreau) Prairie, AB) Talisman acq. + Expansion 2012 Encana divestiture (Steeprock = 198 MMcf/d (sour) Veresen/ Encana Cutbank Complex (Hythe/ Steeprock) $ 915 516 $ 1.8 2012 Shallow Cutbank (BC Montney) Hythe = 340 MMcf/d (sweet) , 176 MMcf/d (sour)) Keyera/ Whitecap Cynthia Plant (NW Alberta) $ 113 78 $ 1.4 2014 Deep-cut North West Alberta Includes some upstream assets Total $ 1,358 $ 1,019

NEW GAS PLANT INVESTMENTS NGLs Capacity Company Plant Costs ($MM) Capacity (MMcf/d) $MM/ MMcf/d Comissioning Date Type Location Notes (kb/d) bbl/MMcf Spectra Energy Dawson Processing Plant Phase I $ 400 200 $ 2.0 2012 Deep Cut Dawson Creek (NE BC) n/a n/a n/a AltaGas Gordondale $ 235 120 $ 2.0 2012 Deep Cut Gordondale Area (AB) Long-term EnCana Contract 11 90 Pembina Pipeline Corporation Musreau I Expansion $ 101 200 $ 0.5 2012 Deep Cut Addition Cutbank Complex (AB) Construction + Expansion/ Encana. Operational in Feb 2012 10 50 AltaGas Harmattan Co-Stream $ 87 250 $ 0.3 2012 Co-stream expansion Cochrane/ Harmattan Co-stream project (similar to a straddle plant) n/a n/a Spectra Energy Dawson Processing Plant Phase II $ 400 200 $ 2.0 2013 Deep Cut Dawson Creek (NE BC) n/a n/a n/a Williams Canada Turbo Expander at Suncor Upgrader $ 225 2013 Deep Cut Fort Mc. Murray Process modification or addiiton of Turbo Expander 10 n/a 13 kb/d extraction, modification & expansion of shallow cut gas Pembina Pipeline Corporation Resthaven $ 230 200 $ 1.2 2014 Deep Cut Cutbank Complex (AB) plant 13 65 Q42013, 100% owned by Paramount (~30 kb/d NGLs, 10 kb/d Paramount Resources Musreau Deep Cut $ 230 200 $ 1.2 2014 Deep Cut Cutbank Complex (AB) (33%) C2) 30 150 100% contracted, 10 yr (connected to Talisman's Wild River & Bigstone gas plants. Talisman to increase recoveries to ~70 Saturn Complex (near Hinton, bbl/MMcf from ~10 bbl/ MMcf). Total 13.5 kb/d of NGLs (70% Pembina Pipeline Corporation Saturn I $ 200 200 $ 1.0 2014 Deep Cut AB) C2). Late 2013 14 68 QuickSilver Resources Fortune Creek Gas Plant $ 175 150 $ 1.2 2012 Shallow Cut Horn River (NE BC) Phase I. Total capacity all phases: ~600 MMcf/d = $760 MM n/a n/a Keyera Corp. Simonette (Modifications) $ 90 100 $ 0.9 2014 Shallow Cut/ Deep Cut NW AB NuVista Energy contract/ Possible future deep-cut n/a n/a Two phases of 400 MMcf/d each for about 800 MMcf/d (Phase Enbridge Cabin Gas Plant Complex $ 1,100 800 $ 1.4 2015 Shallow Cut Horn River I: 2012, Phase II: 2015) n/a n/a Includes pipeline connection to Boreal pipeline and supporting Williams Canada Cryogenic Off-Gas Plant at CNRL Horizon Upgrader $ 300 83 $ 3.6 2015 Deep Cut (C2+/C2= Mix) Fort Mc. Murray facilities 18 217 Keyera Corp. Rimbey Turbo Expander $ 210 400 $ 0.5 2015 Deep Cut West Central AB Long-term ethane purchase agreement 20 50 Pembina Pipeline Corporation Musreau II $ 110 100 $ 1.1 2015 Shallow Cut Cutbank Complex (AB) Gas Plant + Associated Facilities 5 50 Pembina Pipeline Corporation Saturn II $ 170 200 $ 0.9 2015 Deep Cut Saturn Complex (AB) 65% contracted, 10 yr (130 MMcf/d, 13 kb/d NGLs) 13 65 Mistral Midstream/ SaskEnergy Viewfield (SK), Bakken Straddle Plant $ 75 50 $ 1.5 2015 Deep Cut Straddle Plant Viewfield (SK) To be tied to Vantage Pipeline 4 80 Total $ 4,338 3,474 147

NGLS FRACTIONATION INVESTMENTS

Company Plant/ Fractionator Costs ($MM) Capacity (kb/d) $MM/ kb/d Comissioning Date Type Location Notes Pembina Pipeline Corporation Rewater Fort Saskatchewan (RFS) Expansion $ 15 8 $ 1.9 2012 C2+ Fractionator Fort Saskatchewan 2012 Completion Williams Canada De-ethanizer at Redwater $ 225 17 $ 13.2 2013 De-ethanizer Fort Saskatchewan Adding de-C2 capacity Underpinned by a large deep basin producer (Possibly Keyera Corp. Keyera Fort Saskatchewan (KFS) Expansion $ 145 30 $ 4.8 2014 De-ethanizer Fort Saskatchewan Paramount) Pembina Pipeline Corporation Rewater Fort Saskatchewan (RFS) Twinning = RFS II $ 415 73 $ 5.7 2015 C2+ Fractionator Fort Saskatchewan 97% contracted, 10 yr, C2 to NOVA Chem. Williams Canada Redwater Expansion $ 300 13 $ 23.1 2015 Required expansion Fort Saskatchewan Expansion required to accommodate growing volumes Keyera Corp. KFS Twinning $ 220 35 $ 6.3 2016 C3+ Fractionator Fort Saskatchewan Twinning of KFS. Increasing capacity to 65 kb/d Pembina Pipeline Corporation RFS I & II Debottlenecks $ 65 18 $ 3.6 2016 Debottlenecks Fort Saskatchewan Debottleneck increases each frac capacity by 9 kb/d Pembina Pipeline Corporation RFS III $ 400 73 $ 5.5 2016 C2+ Fractionator Fort Saskatchewan (CERI Speculative, most likely to proceed given pipeline exp.) Total $ 1,785 $ 267

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NGLs PIPELINES INVESTMENTS

Company System Costs ($MM) Capacity (kb/d) $MM/ kb/d Comissioning Date Type Location Ft. McMurray --> Fort Williams Energy Canada Boreal Pipeline Construction $ 300 43 $ 7.0 2012 HVP Pipeline (New build) Saskatchewan Plains Midstream Rainbow Pipeline II NGL Expansion $ 200 n/a 2013 LVP System Expansion NW AB --> Fort Saskatchewan NGL Expansions (HVP System: Northern + Peace) Pembina Pipeline Corporation Phases I + II $ 515 105 $ 4.9 2014 HVP System Expansion NW AB --> Fort Saskatchewan Mistral Midstream Vantage Pipeline $ 300 43 $ 7.0 2014 HVP Pipeline (Spec C2) Bakken (ND,SK) --> AEGS Pembina Pipeline Corporation Peace LVP (Crude + Condensate) $ 280 95 $ 2.9 2014 LVP System Expansion NW AB --> Fort Saskatchewan Kinder Morgan Cochin Pipeline Reversal $ 260 95 $ 2.7 2014 Flow Reversal US Midwest --> AB Phase III Expansion (assumes 50% allocation of $2B announcement to NGLs infrastructure and 50% to Pembina Pipeline Corporation crude oil infrastructure: CERI assumption) $ 1,000 135 $ 7.4 2016 HVP & LVP System Expansion NW AB --> Fort Saskatchewan Total $ 2,855 381

OTHER NGLs ASSOCIATED MIDSTREAM INVESTMENTS

Company Asset Costs ($MM) Comissioning Date Keyera Corp. South Cheecham Rail & Truck Terminal $ 68 2013 Pembina Pipeline Corporation Cavern Development & Terminal/ Hub Services $ 375 2014 Pembina Pipeline Corporation RFS II upsize/ Accommodate RFS III Prospect $ 25 2014 Total $ 468

Deep Cut Plants Expansion & New Builds / Straddle Plants/ Co-stream Facilities $468 4% $1,785 $2,953 NGLs Pipelines 17% 27%

Other Gas Processing/ NGLs Extraction Facilities (Mainly Shallow Cut)

$1,358 13% Producer-owned Midstream Divestitures

NGLs Fractionation $1,385 $2,855 13% 26% Other Midstream Assets (Storage & Logistics)

Total: $10,804 MM (2011 - 2016)

Source: BCMJTST,110 Industry data, CERI research, and GOA data.111 Tables and figure by CERI

110 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 111 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 57 Part II – Midstream and Downstream Infrastructure Table 3.2: Alberta's Incremental Ethane Extraction Program (IEEP): Projects Information, 2012112

C2 Volumes Royalty Credits Expected Onstream Commissioned Applicant Project Description (kb/d) ($MM) Status Date by Delivery Point Dow Chemicals Empress V Deep Cut Project Increasing the C2 recovery at the Empress V plant 7 $ 23 Approved (2008) Onstream IPF/ Plains AEGS Dow Chemicals Rimbey Ethane Extraction Project Modification of Keyera's Rimbey Gas Plant to 5 $ 16 Approved (2008) Onstream Keyera AEGS optimize removal and extraction of C2 NOVA Chemicals Williams Off-Gas Ethane Extraction Project (Phase I) Installation of equipment enabling capture of 10 $ 33 Approved (2010) 2014 Williams Petrochemical ethane and ethylene out of off-gases Facility (via Boreal) NOVA Chemicals Hidden Lake Streaming Project Pipeline valve and piping cross-over installations to 3 $ 9 Approved (2010) n/a NGTL n/a direct NGL rich gas Alberta extraction plants NOVA Chemicals Harmattan Plant Co-Stream Project Installation of equipment and pipeline 9 $ 30 Approved (2011) Onstream Altagas AEGS infrastructure to optimize extraction and removal of C2 Dow Chemicals Musreau Deep Cut Project Installation of equipement and modfication of 6 $ 20 Approved (2011) Onstream Pembina HVP Pipeline to Ft. Sk. existing process to maximize C2 extraction and (Fractionators) removal Shell Chemicals Shell Waterton Incremental NGL Recovery Project Alteration of exisitng infrastructure at Waterton to 1 $ 3 Approved (2011) Onstream Shell AEGS increase NGL recovery in Alberta at export point Shell Chemicals Scotford Fuel Gas Recovery Project Installation of various equipment and modification 1 $ 4 Approved (2011) Onstream Shell Petrochemical of processes to extact C2 from Scotford refinery Facility (on site)

Dow Chemicals Rimbey Turbo Expander Project Modification of exisitng Rimbey gas plant by 15 $ 49 Approved (2012) 2015 Keyera AEGS installing a turbo expander to improve C2 recovery

NOVA Chemicals Williams Off-Gas Ethane Extraction Project (Phase II) Increase the ethane removed from off-gases from 10 7 $ 64 Approved (2012) 2015 Williams Petrochemical to 17 mb/d Facility (via Boreal) Dow Chemicals Resthaven Facility Phase 1 Modification and expansion of existing gas plant for 7 $ 21 Approved (2012) 2015 Pembina HVP Pipeline to Ft. Sk. C2 extraction in NW Alberta (Fractionators) Shell Chemicals Shell Scotford Upgrader Off-gas Project Installationf of infrastructure capable of capturing 3 $ 27 Approved (2012) Onstream Shell Petrochemical ethane off-gases from Scotford Upgrader Facility (on site) NOVA Chemicals AltaGas-Gordondale Deep Cut Project Construction of a new gas processing plant in NW 4 $ 13 Approved (2012) Onstream Altagas HVP Pipeline to Ft. Sk. Alberta which will capture ethane from natural gas (Fractionators) production NOVA Chemicals Judy Creek Ethane Extraction Project Increase of storage capacity and plant 3 $ 9 Approved (2012) n/a n/a HVP Pipeline to Ft. Sk. modifications to improve utilization of the existing (Fractionators) facility for C2 extraction Shell Chemicals Shell Jumping Pound Project Aggregation of several small investments to improve 1 $ 3 Approved (2012) Onstream Shell AEGS efficiency at Jumping Pound facility for improved C2 extraction Dow Chemicals Project Turbo (Saturn Plant) Modification of the existing Saturn Gas plant with 8 $ 27 Approved (2012) 2014 Pembina HVP Pipeline to Ft. Sk. the installation of a cryogenic turbo expander to (Fractionators) improve C2 extraction Total 16 89 $ 351 Source: CERI research, and ADOE113 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

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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) 600 542 Peace HVP System Expansion (Phase III) 517 Peace HVP System Expansion (Phase II) 483 500 451 Peace HVP System Expansion (Phase I) Judy Creek 385 385 385 385 385 385 385 385 385 385 396

400 Bonnie Glen kb/d 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 100 Peace HVP System (NGLs) 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)* *CERI Estimate Williams Redwater Expansion I (CNRL) KFS II RFS III 492 497 500 RFS II Williams Redwater Keyera Fort Saskatchewan (KFS) 432 Dow Fort Saskatchewan (DFS) Redwater Fort Saskatchewan (RFS) 400 BP Fort Saskatchewan Total Fort Saskatchewan Fractionation Capacity (kb/d) 339 Total C2+ Fractionation Capacity 289 289 289 289 289 289 289 289 289 289 296 296 296

300 kb/d

200

100

- 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Source: CERI

116 Latest date for which expansions have been announced as of the time of writing

May 2014 Natural Gas Liquids (NGLs) in North America – An Update 59 Part II – Midstream and Downstream Infrastructure 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 Asset/ Notes Costs ($MM) Comissioning Date Ontario Cracker Revamp (increase NGLs use/ reduce Nova Chemicals heavy feed) $ 250 2013 PE1 Expansion (Building R3)/ E2 Upgrades & Nova Chemicals Refurbishment $ 1,000 2015 Nova Chemicals Sarnia Growth Projects (Expansion + Debottlenecks) $ 300 2016 Williams Canada Propane Dehydrogenation (PDH) Plant $ 900 2016 Pembina Pipeline Corporation LPG Export Terminal $ 1,000 2015 Altagas LPG Export Terminal $ 500 2016 Total $ 3,950

$900 LPG Export Terminals 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.

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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 61 Part II – Midstream and Downstream Infrastructure 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.

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May 2014 Natural Gas Liquids (NGLs) in North America – An Update 63 Part II – Midstream and Downstream Infrastructure Appendix I – Canadian NGL Infrastructure

Source: CERI from PennWell MAPSearch

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Appendix II – United States NGL Infrastructure

Source: CERI from PennWell MAPSearch

May 2014