Study No. 130 July 2012
CANADIAN NATURAL GAS LIQUIDS IN ENERGY RESEARCH NORTH AMERICA: OVERVIEW INSTITUTE AND OUTLOOK TO 2035
Canadian Energy Research Institute | Relevant • Independent • Objective
NATURAL GAS LIQUIDS IN NORTH AMERICA: OVERVIEW AND OUTLOOK TO 2035
Natural Gas Liquids in North America: Overview and Outlook to 2035
Copyright © Canadian Energy Research Institute, 2012 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute
ISBN 1-927037-09-6
Author: Carlos A. Murillo
Acknowledgements: The author wishes to acknowledge Rick Funk of Funk & Associates Inc. and Paul Kralovic of Kralovic Economics Inc.; as well as those involved in the production, reviewing, and editing of the material, including but not limited to Peter Howard and Megan Murphy.
CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Canada www.ceri.ca
July 2012 Printed in Canada
Front cover photo courtesy of ATCO Midstream. Natural Gas Liquids in North America: Overview and Outlook to 2035 iii
Table of Contents
LIST OF FIGURES ...... v LIST OF TABLES ...... xi REPORT HIGHLIGHTS & SUMMARY ...... xiii INTRODUCTION ...... xix CHAPTER 1 NATURAL GAS LIQUIDS AND THE CANADIAN INDUSTRY ...... 1 Natural Gas Liquids Overview ...... 1 Natural Gas Liquids in Canada ...... 15 CHAPTER 2 NATURAL GAS LIQUIDS SUPPLY AND DEMAND IN CANADA...... 71 Canadian NGL Supply and Demand Forecast: Methodology ...... 71 Alberta NGLs Outlook and Analysis ...... 89 Canadian Outlook for Propane and Butanes ...... 100 Summary and Conclusions ...... 103 CHAPTER 3 NATURAL GAS LIQUIDS SUPPLY AND DEMAND IN THE UNITED STATES .... 105 Forecasting Methodology ...... 105 PADD by PADD Overview and Forecast ...... 120 Summary and Conclusions ...... 160 APPENDIX A PETROLEUM ADMINISTRATION AND DEFENSE DISTRICTS (PADD DISTRICTS) AND RELATED STATES ...... 165 APPENDIX B NATURAL GAS LIQUIDS INFRASTRUCTURE IN THE UNITED STATES ...... 167
July 2012 iv Canadian Energy Research Institute
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 v
List of Figures
E.1 CERI’s Ethane Supply and Demand Analysis and Outlook, 2004-2035 ...... xv E.2 CERI’s Pentanes Plus Supply and Demand Analysis and Outlook, 2004-2035 ...... xvi E.3 CERI’s PADD I Ethane Supply and Demand Forecast ...... xvii E.4 CERI’s PADD III Propane/Propylene Supply and Demand ...... xvii 1.1 Methane and Other Paraffin Hydrocarbons ...... 2 1.2 Isomers (top) and Naphthenes (bottom) ...... 3 1.3 Natural Gas Liquids ...... 5 1.4 Raw Natural Gas Composition ...... 5 1.5 Sample Raw Gas Compositions ...... 6 1.6 Canadian Crude Oil Samples, Light versus Heavy ...... 7 1.7 North American Natural Gas Liquids Fairways ...... 8 1.8 Natural Gas Liquids in the WCSB and Alberta ...... 8 1.9 From Hydrocarbons to End Products ...... 9 1.10 Natural Gas Processing ...... 10 1.11 Natural Gas Liquids Fractionation ...... 11 1.12 Midstream Processes and Facilities ...... 12 1.13 Refinery Processes, Configuration, and Products ...... 13 1.14 Underground and Above Ground NGLs Storage Facilities ...... 14 1.15 Canadian Natural Gas Liquids Productions by Source (mb/d) and Raw Natural Gas Production (MMcf/d), 2000-2010 ...... 16 1.16 Canadian Raw Natural Gas Production by Province (MMcf/d) and Average Monthly Natural Gas Price @ AECO ($/GJ), 2000-2010 ...... 18 1.17 Economics of Dry versus Liquids-rich Natural Gas (Montney), Supply Costs, 2011 ...... 19 1.18 NGLs Production (mb/d) and Raw Natural Gas Production (MMcf/d) in Canada, 2002-2010 ...... 19 1.19 Canadian Refinery Production of LPGs (mb/d), Refineries Crude Slate (md/b & percent) 2000 to 2010, and 2010 Refined Petroleum Product Breakdown (mb/d & percent) ...... 21 1.20 Synthetic Crude Oil Production and Capacity by Project (mb/d), Oil Sands Mined & Processed (mt/d), and Off-Gas Production from Upgraders (MMcf/d) and Use (percent), 2008-2011 ...... 24 1.21 Illustration of Williams’ Fort McMurray Extraction Plant ...... 25 1.22 NGLs Supply and Demand ...... 27 1.23 Petrochemical Production in Canada ...... 28
July 2012 vi Canadian Energy Research Institute
1.24 Ethane Supply and Demand Balance (mb/d) and Natural Gas Production, Export, and Demand Trends in Alberta (MMcf/d), 2002-2Q2012 ...... 30 1.25 Ethane Supply Sources and Gathering and Delivery Systems in Alberta, 2012 ...... 31 1.26 Ethane Production in Alberta by Source, 2002-Q122012 ...... 32 1.27 Propane Supply and Demand in Canada, 2000-2010, Supply and Demand Balance and Propane Production in Alberta, 2002-2011, (mb/d) ...... 36 1.28 Propane Production in Alberta by Source, 2002-Q12012 ...... 37 1.29 Butanes Supply and Demand in Canada, 2000-2010, Supply and Demand Balance and Butanes Production in Alberta, 2002-2011 (mb/d) ...... 38 1.30 Butanes Production in Alberta by Source, 2002 to Q12012 ...... 39 1.31 Canadian Supply/Demand Balance for Pentanes Plus and Condensate, Condensates and Pentanes Plus Charged to Canadian Refineries (mb/d), 2000-2010, and Pentanes Plus Production in Alberta by Source, 2002-Q12012 .... 41 1.32 Increasing Diluent Needed for Oil Sands Operations ...... 42 1.33 Alberta Supply/Demand Balance for Natural Gas Liquids Mix, and NGL Mix Production in Alberta by Source (mb/d), 2002-Q12012 ...... 44 1.34 Canadian NGLs Pricing $/GJ (top) and $/bbl (bottom) ...... 46 1.35 NGLs Prices as a Percentage of Crude Oil (top), NGLs Gross Frac Spread (middle), and Crude Oil Price to Natural Gas Price Ratio (bottom) ...... 48 1.36 NGLs Economics (top) and Common Gas Processing Contract Structures ...... 49 1.37 Major NGL Infrastructure in Canada ...... 50 1.38 Alberta Straddle Plants and Locations ...... 52 1.39 NGLs Infrastructure in Alberta ...... 54 1.40 Map of William Energy’s Alberta Assets ...... 55 1.41 Refining Capacity (mb/d) and Number of Refineries in Canada, by Region, 2011 ...... 56 1.42 AEGS Pipeline System ...... 57 1.43 Cochin Pipeline Reversal Project ...... 58 1.44 Empress-Kerrobert and Enbridge’s Mainline and Southern Lights Pipelines ...... 58 1.45 Spectra Energy and the Empress System ...... 59 1.46 Plains Midstream Pipelines ...... 59 1.47 Vantage Pipeline ...... 60 1.48 Alliance Pipeline ...... 61 1.49 North American Railway Systems ...... 62 1.50 Value-added Chain, Product Prices, and NGLs/Petrochemical Economics ...... 64 1.51 Ethane and Propane and Their Derivative Applications ...... 65 1.52 Canadian Ethylene Cracking Capacity by Location (Tonnes/Year) and Required Feedstock (%) ...... 66
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 vii
1.53 Manufacturing Facilities at Joffre ...... 67 2.1 Changing Dynamics in NGL Markets in North America ...... 71 2.2 Alberta NGLs Market Dynamics ...... 72 2.3 CERI’s Alberta Study Areas & Ethane Reserves ...... 74 2.4 Alberta Natural Gas Remaining Producible Volumes (bcf), Remaining Natural Gas Liquids Reserve (MMb), and Average Natural Gas Liquids Composition (bbl/MMcf), and Natural Gas Molecular Composition (%) by Component, by CERI Study Area (YE2010) ...... 75 2.5 CERI’s Alberta Natural Gas Forecast by Study Area, 2004-2035 ...... 76 2.6 Alberta Field Plants Gas Processing Capacity Throughput (MMcf/d), Liquids Production Capacity and Output (mb/d), Utilization Rates (%) and Liquids Yields (bbl/MMcf), 2002-Q12012 ...... 79 2.7 Modeled Spec Ethane Field Extraction versus Actual, 2002-Q12012 ...... 80 2.8 Fort Saskatchewan Fractionators Total Liquids Production and Feed Sources, 2002-Q12012 (md/d) ...... 81 2.9 Modeled Ethane in NGL Mix Extraction versus Actual, 2002-Q12012 ...... 82 2.10 Modeled Inlet Natural Gas Flows at Cochrane Straddle Plants versus Actual, 2002-Q12012 ...... 83 2.11 Synthetic Crude Oil Production (mb/d), Analysis, Forecast, and Comparison, 2007-2035 ...... 85 2.12 Upgrader Off-Gas Production Analysis, Forecast, and Comparison, 2007-2035 ..... 87 2.13 CERI’s Marketable Natural Gas Analysis, Forecast, and Comparison, 2004-2035 .. 89 2.14 CERI’s Ethane Entrained in the Natural Gas Stream, Analysis, Forecast, and Comparison, 2004-2035 ...... 91 2.15 CERI’s Ethane Supply Analysis, Forecast, and Comparison, 2004-2035 ...... 92 2.16 CERI’s Ethane Supply and Demand Analysis and Outlook, 2004-2035 ...... 93 2.17 CERI’s Propane Supply and Demand Analysis and Outlook, 2004-2035 ...... 94 2.18 CERI’s Butanes Supply and Demand Analysis and Outlook, 2004-2035 ...... 96 2.19 CERI’s Pentanes Plus Supply and Demand Analysis and Outlook, 2004-2035 ...... 97 2.20 CERI’s Natural Gas Liquids Supply and Demand Analysis and Outlook and NGLs Mix Composition, 2004-2035 ...... 98 2.21 Potential Supply of SGLs in Alberta by Components, by Area, and by Level of Recovery, 2007-2035 (mb/d) ...... 99 2.22 Estimated Ethane, Ethylene, and Propane Plus SGLs Available in Oil Sands Off-gases by Area, Component, and Level of Recovery, 2007-2035 (mb/d) ...... 101 2.23 Canadian Propane Supply and Demand Balance, 2004-2035 (mb/d) ...... 102 2.24 Canadian Butanes Supply and Demand Balance, 2004-2035 (mb/d) ...... 102 3.1 Comparison of Shale Gas Threshold Economics ...... 106
July 2012 viii Canadian Energy Research Institute
3.2 US Shale Plays ...... 107 3.3 Baker Hughes Oil and Gas Directed Drilling Rig Counts ...... 108 3.4 Accelerated Supply Build-up Fayetteville versus Barnett ...... 108 3.5 US Dry Gas Resource ...... 110 3.6 Year 2015 Forecast US Gas Supply Provided in Sequential EIA Annual Energy Outlooks with a Comparison to 2011 Actual ...... 110 3.7 Estimated US Dry Shale Natural Gas Production, 2000-2010 ...... 111 3.8 Estimated Annual US Dry Shale Natural Gas Production, 2000 -2011 ...... 111 3.9 US Monthly Shale Gas Production, 2010-2011 ...... 112 3.10 US Natural Gas Production, 1990-2035 ...... 116 3.11 US Ethane Re-Emerges as a Globally Competitive Cracker Feedstock ...... 114 3.12 US Ethane Demand ...... 114 3.13 US Ethane Consumption by PADD (mb/d) ...... 113 3.14 US Ethane Supply by PADD (mb/d) ...... 113 3.15 US Propane/Propylene Consumption ...... 117 3.16 US Propane Supply ...... 117 3.17 US Propane/Propylene Imports ...... 118 3.18 US Propane/Propylene Demand (mb/d) ...... 118 3.19 US Propane/Propylene Supply (mb/d) ...... 118 3.20 US Propane/Propylene Exports ...... 119 3.21 US Propane Imports Less Exports ...... 119 3.22 US Fractionation Capacity Existing & Planned ...... 120 3.23 Example Development Scenario for a 141 Tcf Gas Resource ...... 122 3.23 EIA Forecast Northeast Gas Production ...... 123 3.25 Comparison of Revenues for Dry and Wet Gas Production ...... 124 3.26 Pennsylvania Wet and Dry Gas Rig Counts ...... 127 3.27 PADD I Gas Production with Wet Dry Gas Split ...... 127 3.28 PADD I Ethane Production from Wet Gas Play ...... 129 3.29 PADD I Ethane Supply Demand Forecast ...... 129 3.30 PADD I Gas Plant C3+ Production from Wet Gas Play ...... 130 3.31 PADD I Fractionated Gas Plant NGL Production from Wet Gas Play ...... 131 3.32 PADD I Propane/Propylene Supply Sources ...... 132 3.33 PADD I Propane/Propylene Supply Demand Forecast ...... 133 3.34 North Dakota Forecast of Future Oil Production Scenarios ...... 135 3.35 North Dakota Daily Oil and Gas Production ...... 136 3.36 North Dakota Gas Production ...... 136 3.37 Industry Forecasts of Bakken Production ...... 138
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 ix
3.38 North Dakota Gas Processed and NGL Production ...... 139 3.39 North Dakota Crude Oil and Raw Gas Production ...... 139 3.40 North Dakota Raw Gas Production Forecast ...... 140 3.41 North Dakota Ethane Shipments ...... 141 3.42 North Dakota NGL Shipments ...... 142 3.43 PADD II Dry Gas Production plus Alliance Liquids Rich Gas Imports ...... 143 3.44 PADD II Ethane Supply and Demand Balance ...... 144 3.45 PADD II Monthly Propane Supply Demand History ...... 145 3.46 PADD II Propane/Propylene Supply and Demand ...... 145 3.47 US NGL Pipeline Map ...... 146 3.48 PADD III Ethane/Ethylene Demand ...... 147 3.49 PADD III Ethane/Ethylene Supply ...... 148 3.50 PADD III Propane/Propylene Demand & Exports ...... 149 3.51 PADD III Propane/Propylene Production & Imports ...... 149 3.52 Transfers of Propane/Propylene to PADD III from Other US Regions ...... 150 3.53 EIA Southwest and Gulf Coast Region Gas Supply Forecast ...... 151 3.54 Transfers of Ethane/Ethylene into PADD III ...... 152 3.55 PADD III Ethane Supply/Demand Forecast ...... 153 3.56 PADD III Propane/Propylene Supply and Demand ...... 153 3.57 PADD IV Ethane/Ethylene Demand ...... 154 3.58 PADD IV Ethane/Ethylene Supply ...... 155 3.59 PADD IV Propane/Propylene Demand ...... 155 3.60 PADD IV Propane/Propylene Supply Sources ...... 156 3.61 PADD IV Transfers of Propane/Propylene to PADD III ...... 156 3.62 PADD V Propane/Propylene Demand ...... 157 3.63 PADD V Propane/Propylene Supply Sources ...... 157 3.64 EIA AEO 2012 PADD IV and PADD V Gas Production Forecast ...... 158 3.65 PADDs IV and V Ethane/Ethylene Production Forecast ...... 159 3.66 PADDs IV and V Propane/Propylene Supply and Demand Forecast ...... 160 A.1 PADD Districts ...... 165 A.2 Oil and Gas Supply Model Regions ...... 166 B.1 Gas Processing Capacity in the United States ...... 167 B.2 Major NGL Hubs and Transportation Corridors ...... 167 B.3 New & Repurposed NGL Pipeline Systems ...... 172 B.4 NGLs Content by Basin in the United States ...... 173
July 2012 x Canadian Energy Research Institute
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 xi
List of Tables
1.1 Physical Properties of Paraffin Hydrocarbons ...... 3 1.2 IEEP Projects by Status and by Company (as of August 2012) ...... 34 1.3 Natural Gas Processing Plants in Canada ...... 51 1.4 Alberta Oil Sands Upgraders ...... 56 2.1 Upgrader Off-Gas Analysis ...... 84 3.1 North American Capacity Ethylene Expansion ...... 116 3.2 Existing, Under Construction and Announced Gas Processing Plants in the Bakken ...... 137
July 2012 xii Canadian Energy Research Institute
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 xiii
Report Highlights & Executive Summary
Natural Gas Liquids (NGLs), including ethane, propane, butanes, and pentanes plus; while not well understood, are an essential segment of the North American energy industry. Their sources, including natural gas processing plants, crude oil refineries, and oil sands upgraders; are as diverse as their end-uses which range from the manufacturing of petrochemicals (turned into everyday consumer products), as well as uses such as fuel and heating, but also essential to refineries and oil sands operations.
Advances in crude oil and natural gas stimulation, completion, and production techniques are bringing on substantial increases in supply volumes of these commodities in North America. In some instances, traditional demand or market areas for NGLs have the potential to bring on substantial supply volumes and to become self-sufficient. Further, the development of a wide price differential between high crude oil (global) prices and low natural gas (local) prices, a situation which is expected to continue over the long term, has created incentives for producers to monetize NGLs, whose prices tend to follow oil prices but for which the feedstock price is that of natural gas.
These and many other developments have the potential to result in substantially increasing volumes of NGLs in North America. Whether these opportunities will be acted upon and realized will be dependent on various investments which will be required to process, transport, and market the NGLs. Without a question, market dynamics are changing in the NGLs context and thus it is important to explore in a relevant, independent, and objective fashion some of the opportunities, challenges, risks, and the overall changes that could transform this segment of the energy industry in North America
It has been over ten years since the last time CERI made an assessment of NGLs markets in North America. This study aims to provide a reference tool to gain an understanding of the industry and concurrent developments with a focus on Canada, but also to develop a forecast for NGLs in Canada and the United States to 2035. The main results of this study are highlighted below:
Natural Gas Liquids and the Canadian Industry The Canadian NGLs industry is centered on the Western Canada Sedimentary Basin (WCSB), with a number of other important facilities such as gas plants, fractionators, and refineries located in Ontario, Quebec, and Atlantic Canada. While the main source of NGLs in Canada is natural gas processing plants, refineries also produce NGLs, mainly propane and butanes. Further, oil sands upgraders’ off-gases hold the promise of potential large increases of NGLs supplies. Canada has a robust NGL infrastructure that includes hundreds of gas processing plants, straddle plants, fractionation plants, refineries, oil sands upgraders, a complex network of pipelines as well as various storage locations. This is an important segment of the Canadian energy industry.
July 2012 xiv Canadian Energy Research Institute
Canada’ petrochemical industry, primarily centered in Alberta, is a major user of NGLs, primarily ethane, and plays an important role in processing raw resources to value-added products thus contributing to the Canadian economy.
Propane is mainly used for heating and fuel purposes across Canada with the major users being the industrial and commercial sectors. Small volumes of propane are also used by Canadian petrochemical plants, mainly in Eastern Canada.
Butanes are used by refineries to blend in the gasoline pool, as well as by petrochemical producers, and lately have increasingly been used as a diluent agent for crude bitumen. Diluent for oil sands operations allows crude bitumen to flow as regular crude would on the pipeline transportation infrastructure.
Pentanes plus are used primarily as a diluent for oil sands operations, a demand source that continues to grow rapidly given the number of oil sands projects coming online. Pentanes plus are also used at the refinery level to be blended in the gasoline pool but this use has declined significantly in Canada over the last few years
Natural Gas Liquids Supply and Demand in Canada The outlook for NGLs in Canada has taken into consideration all the major components of the natural gas processing infrastructure, as well as CERI’s natural gas supply forecast and gas composition analysis. Further, the potential for extraction of NGLs from oil sands upgraders’ off-gases was incorporated. Other emerging supply sources such as ethane imports are also included in this analysis. Refineries and overall demand trends were the remaining pieces of the analysis.
While the Alberta petrochemical business has seen a decrease in ethane availability over the last few years due to a combination of lower natural gas production and export volumes, new developments are changing that picture. Declining gas prices have sent producers to focus their efforts on exploring and developing liquids-rich gas resources thus resulting in a richer gas stream even though natural gas volumes have continued on a decline trend. CERI’s forecast for recovering natural gas volumes from the WCSB, coupled with increasing ethane volumes extracted from oil sands off-gases, increases from Alberta’s Incremental Ethane Extraction Policy (IEEP) projects, and ethane imports from the Bakken in North Dakota, will result in increasing utilization at the four currently existing ethylene crackers.
A continuation of these events could lead to the expansion of the current petrochemical facilities capacity or even the construction of new facilities as seen in Figure E.1.
In regards to propane, the market will continue to have enough volumes to meet local demand and thus export any surplus volumes. While over the next few years overall supply volumes are bound to decline given the natural gas production forecast, the later part of the forecast period will see supply volumes return to historical levels (see Figures 2.17 and 2.23).
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 xv
Figure E.1: CERI’s Ethane Supply and Demand Analysis and Outlook, 2004 - 2035
Sources: ERCB data for comparison purposes, CERI analysis
The reversal of the Cochin pipeline (for diluent use), which is currently an important outlet for propane exporters in the WCSB, will pressure propane prices causing differentials to widen enough for exports to be able to cover rail transportation or similar costs in order to continue exports to traditional markets in the United States. Alternatively, propane producers might consider new export markets. Further, both propane and butanes (together liquefied petroleum gases or LPGs) have been investigated by oil sands producers for solvent aided steam assisted gravity drainage (SAGD) developments, while some service companies are exploring the use of LPGs for fracking operations. These developments can provide additional local demand to use WCSB propane supplies.
Butanes are increasingly being used as a diluent by oil sands producers while supplies will continue on a decline trend over the next few years. The market is expected to be tight and eventually imports volumes will be required to meet increased demand volumes (see Figures 2.18 and 2.24).
In regards to pentanes plus, the supply picture looks different than for all other liquids in Canada. CERI estimates that oil sands developments may need close to 1.4 million barrels per day (1,400 mb/d) of pentanes plus and condensate in order to be able to move incremental volumes of crude bitumen to export markets by the end of the forecast period. These volumes are well in excess of local supplies thus indicating that the majority of these supplies will need to be imported as seen on Figure E.2. While various pipeline systems are designed to carry diluent to oil sands operations including the Southern Lights pipeline, the proposed reversal of the Cochin pipeline, and the proposed Northern Gateway condensate line, their supply volumes will account for a fraction of the required volumes.
July 2012 xvi Canadian Energy Research Institute
Figure E.2: CERI’s Pentanes Plus Supply and Demand Analysis and Outlook, 2004 - 2035
Sources: ERCB and NEB data for comparison purposes, CERI analysis
Provided that these imported supplies can be acquired at reasonable prices, oil sands producers will continue to acquire diluent supplies from external markets and develop the necessary infrastructure for their transportation. Alternatively, given the proper market conditions, further development of upgrading capacity in Alberta would reduce the need for diluent volumes.
Synthetics Gas Liquids (SGLs), a combination of NGLs and other liquids have the potential to provide over 160 thousand barrels per day mb/d of increased liquids supply in Canada. This can in turn support the development of value-added industries in Canada (see Figures 2.21 & 2.22).
Natural Gas Liquids Supply and Demand in the United States In the United States the rapid level of development in NGLs markets has meant that the needed infrastructure required to extract, process, transport, and use NGLs is lagging behind. CERI estimates supplies of NGLs in the United States to rise to new highs driven by shale gas development in several basins across the country.
Increased supply of ethane and propane is causing congestion on the Conway, Kansas to Mont Belvieu, Texas transportation corridor. This is resulting in wide Conway to Mont Belvieu basis differentials that will only be relieved once incremental transportation capacity is completed over the next couple of years.
Estimated increasing ethane supplies in the United States are large enough to support the addition of several new world-scale ethylene crackers. PADD I (US Northeast), currently producing no ethane, will add enough new ethane production capability to support an ethylene cracker in the area and still have sufficient volumes to be exported to Ontario, as well as to be transferred to PADD III (US Gulf Coast), the largest market in North America (Figure E.3).
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 xvii
Figure E.3: CERI’s PADD I Ethane Supply and Demand Forecast
Source: CERI analysis
Forecast US propane supply increases are large enough to cause substantial net propane exports (Figure S.4) for all months except peak winter demand months. Additions of facilities to substantially increase propane export capacity is under construction at the Gulf Coast (PADD III). Mont Belvieu propane prices will need to adjust so that (except for winter peak demand months) prices trade at a sufficient discount to international propane prices to support refrigeration and shipping costs to international markets.
Figure S.4: CERI’s PADD III Propane/ Propylene Supply and Demand
Source: EIA historical data, CERI analysis
July 2012 xviii Canadian Energy Research Institute
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 xix
Introduction
With diminishing natural gas production in the Western Canada Sedimentary Basin (WCSB), there is a perception in industry and government that Natural Gas Liquids (NGLs)1 supply may suffer a decline—by some outlooks, a permanent decline. This pessimism is not helped by the fact that natural gas prices are near-record low levels.
That being said, while British Columbia’s promising shale play, the Horn River Basin, is liquids- poor, or dry, there are other shale plays, such as the Montney shale that are liquids-rich and drawing attention. Remote areas accessed by two proposed gas pipelines in the north, Alaska and Mackenzie Valley, also hold large quantities of liquids and could eventually offer substantial supply2. Further, oil sands upgraders’ off-gases have the potential to add to the supply of liquids in Alberta, and investments are being made in this area.
At any rate, the removal and upgrading of NGLs from the gas stream is big business in Canada, particularly for Alberta and Ontario. End-uses for NGLs are diverse, from providing raw materials for oil sands operations, oil refineries and petrochemical plants, to sources of energy. Integrated petrochemical complexes in Canada are located primarily in Joffre and Fort Saskatchewan, Alberta and Sarnia, Ontario. These petrochemical clusters play an important role in producing goods used for industrial and consumer products and are thus an important source of value added manufacturing in Canada. As an example, in 2010, Alberta’s petrochemical industry, which utilizes primarily ethane as a feedstock, produced products valued at C$10.5 billion and exported C$6.2 billion worth of petrochemical/ chemicals.3
But natural gas liquids are not only important in Canada. South of the border, in the United States, natural gas liquids production is increasing at such rapid pace that the needed infrastructure to extract, processes, transport and use these liquids is lagging behind all the new developments.
Production of gas liquids from various emerging plays such as the Bakken, Eagle Ford, and the Marcellus hold the potential to significantly increase the liquids supply in the US over the long term. The petrochemical industry in the US is meanwhile re-tooling and expanding to take advantage of this opportunity. On the other hand, increasing supplies from traditional market (demand) regions means that overall market dynamics are changing and evolving. This has implications for both Canada and the United States.
This report’s primary goal is to make sense of all the changing market dynamics and developments which surround the supply and demand of natural gas liquids in North America
1 Not to be confused with liquefied natural gas (LNG). 2 While these two pipeline projects are mentioned here because of their liquids potential, there is however, a large degree of uncertainty of whether an when these projects will get built and therefore supplies from these sources are considered in CERI’s analysis. 3 Government of Alberta, Alberta’s Energy Industry: An Overview, June, 2010, pp. 3
July 2012 xx Canadian Energy Research Institute
while providing an outlook for NGLs supply and demand to 20354. Further, this report will serve as an educational tool that will enhance the understanding of a segment of the energy industry (NGLs) which is essential but not well known, with a focus on Canada.
The first chapter is meant to be an overview of the NGLs industry, and will lay the foundation for further analysis. This chapter will introduce natural gas liquids including some basic definitions, while identifying supply sources and the needed process to extract the liquids Further, this chapter will provide production volumes as well as supply and demand balances for each liquid in Canada, explain pricing dynamics and some basic economics surrounding liquids extraction, and will present an overview of the existing infrastructure which serves to connect producers and end-users.
Chapter 2 will presents CERI’s outlook for Canadian natural gas liquids supply and demand. The first section of this chapter will explain CERI’s methodology for forecasting the supply and demand of NGLs in Canada, while the second section will present our forecast results together with a brief discussion and analysis. An overall summary and conclusions section is presented at the end of this chapter.
Chapter 3’s first section will present CERI’s overview of NGLs developments in the United States together with supply and demand balances (with a focus on ethane and propane), and will elaborate on CERI’s methodology for forecasting NGLs supply and demand in the United States. Chapter 3 will further present a region by region (PADD5) overview and forecast for both ethane and propane in the United States, and will conclude with a brief summary of the main findings.
Appendices A and B provide supplementary information on CERI’s regional analysis for the US as well as some maps that illustrate the NGLs infrastructure in the US for reference purposes.
It has been more than ten years since the last time CERI prepared a market overview and outlook for NGLs in North America. With the current pace of developments in these markets and the continuously changing dynamics, this is CERI’s relevant, independent, and objective contribution to the understanding of these issues.
4 In the context of this report North America refers to Canada and the United States. 5 Petroleum Administration for Defense Districts
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 1
Chapter 1: Natural Gas Liquids and the Canadian Industry
To better understand the state of natural gas liquids (NGLs) today and gauge how the market will develop in the future, it is important to understand the state of the industry.
In this chapter, CERI presents a brief overview of NGLs, identifies supply sources as well as some of the processes required to extract the liquids. Further, CERI explores the NGLs industry in Canada, from production volumes to supply and demand (S/D) balances for Alberta and Canada. Pricing and infrastructure in the Canadian context are also presented in this chapter.
Natural Gas Liquids Overview
Petroleum and Hydrocarbons To understand natural gas liquids, a basic understanding of petroleum and hydrocarbons is necessary.
Petroleum is the most basic building block of the energy industry. In the context of this report, petroleum encompasses crude bitumen, conventional crude oil, natural gas liquids, and natural gas. Petroleum is a mixture of hydrocarbon compounds (organic molecules) as well as some other non-energy components and impurities. Hydrocarbons, in turn, are molecules made up of hydrogen and carbon atoms in different proportions.
Heavier hydrocarbons tend to have higher heat content. Lighter hydrocarbons have lower heat content. The molecular weight and the sulphur content are some of the most important characteristic of hydrocarbons as they would dictate the required level processing as well as their end uses.
Paraffin hydrocarbons (a.k.a. alkanes) are saturated hydrocarbons (only single bonds between carbon atoms) or straight-chain compounds that have a molecular formula defined by CnH2n+2 where C is the carbon atoms, H is hydrogen, and n is an integer. Therefore, paraffins are defined by having double the number of hydrogen atoms plus two, than the number of carbon atoms. One important physical property of paraffin hydrocarbons is that, at room temperature, those with less than five carbon atoms exist in a gaseous state, those with between five and 15 carbon atoms exists in a liquid state, and those with over 15 carbon atoms exist as waxes and solids.
Methane (CH4) is the lightest paraffin hydrocarbon and it is characterized by being lighter than air in a gaseous state and lighter than water (H2O) in a liquid state. Methane is also non-toxic, odorless, colorless, and highly flammable. Natural gas used at home for heating purposes is mainly methane.
July 2012
2 Canadian Energy Research Institute
Other normal (straight-chain) paraffin hydrocarbons include ethane (C2H6), propane (C3H8), 1 normal butane (C4H10), and normal pentane (C5H12). These are displayed together with methane (CH4) on Figure 1.1.
Figure 1.1: Methane and Other Paraffin Hydrocarbons
Source: CERI
Generally speaking the names given to these hydrocarbons is commonly abbreviated by using a C and the number of carbon atoms. For example ethane is known as C2, propane as C3, butanes as C4, and pentanes plus as C5+.
Hydrocarbons such as butanes and larger molecules can exist both as straight-chains (normal) or branch chains. These branch shaped hydrocarbons are known as isomers, iso-paraffin hydrocarbons or iso-alkanes. They have the same molecular formula but different molecular structure and physical structure. As an example, normal butane (n-butane) and iso-butane (i- butane) are displayed in Figure 1.2 (top).2
More complex hydrocarbons are known as naphthenes or cycloparaffin hydrocarbons. These are composed of one or more single ring structures, and are usually hydrocarbons with five or six carbon atoms. Crude oil as an example can have a 30 to 60 percent composition of naphthenes. Figure 1.2 displays both cyclopentane and cyclohexane (bottom).
Table 1.1 provides an overview of some of the physical properties of various paraffin hydrocarbons.
1 For the purpose of this report pentanes plus includes pentanes, hexanes, and heptanes. 2 For the purpose of this report, normal and iso butane are reported together as butanes.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 3
Figure 1.2: Isomers (top) and Naphthenes (bottom)
Source: CERI
Table 1.1: Physical Properties of Paraffin Hydrocarbons
Source: CERI
July 2012
4 Canadian Energy Research Institute
Other types of hydrocarbons include asphaltenes which are complex and heavy hydrocarbons that are insoluble in light paraffin hydrocarbons and therefore occur as solids in crude oil; as well aromatics, which are based on the structure of the benzene ring, where each second carbon bond is a double bond and include benzene, toluene, ethyl-benzene, and xylene, and can be used as petrochemical feedstock.
Alkenes or olefins are doubled bonded carbon to carbon compounds and are the main building blocks of the petrochemical industry including ethylene, propylene, and butadiene. This last group of hydrocarbons (olefins) are produced by human controlled chemical reactions such as steam cracking of ethane, propane, and butanes, and do not normally occur in nature.
The important take away from this quick overview of the different hydrocarbon components is that each hydrocarbon is unique and has unique physical properties including their molecular structure, boiling point, vapour pressure, density, and heating values.
These are important considerations as we get into the discussion of the different sources and uses of natural gas liquids.
Natural Gas Liquids: Key Definitions Natural gas liquids are the light hydrocarbons that are dissolved in natural gas in a reservoir and are produced with the gas stream. These include ethane, propane, butanes (both normal and iso-butane), pentanes plus and gas condensate, or hydrocarbons with between two and eight carbon atoms (C2H6 – C8H18), both in gaseous and liquid form.
Once extracted, above the ground the (rich) raw gas stream is unstable as heavier (C5+) components will condense (liquids state) at atmospheric pressure, while lighter components normally remain in a gaseous form and will be separated from the natural gas (methane) in a processing plant. Therefore, NGLs can be split between condensates or heavier fractions (C5+), and other NGLs (C2, C3, and C4). 3
Liquefied petroleum gases (LPGs) is a term used to refer to propane, butanes, and a combination of both but it is also the term used for NGLs produced by refineries, which are primarily propane and butanes.
Pentanes plus (C5+) refers to pentanes and heavier hydrocarbons extracted from the natural gas including iso-pentane, natural gasoline, and plant condensate. Natural gasoline is an NGL whose main components are hydrocarbons in the C5 to C6 range, which are also commonly referred to as naphtha. Condensate is the liquids fraction which is dissolved in the reservoir and that condenses to a liquid at atmospheric conditions.4
Figure 1.3 illustrates the differences between the different components as explained above.
3 Source: International Energy Agency (IEA), Natural Gas Liquids Supply Outlook 2008 – 2015, April 2010 4 Ibid.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 5
Figure 1.3: Natural Gas Liquids
Source: International Energy Agency (IEA)5
Sources of Natural Gas Liquids
Natural Gas Natural gas is currently the main source of NGLs. In its natural form (raw or unprocessed) natural gas is made of various components including methane (the main source of the natural gas used for heating and electricity) as well as ethane, propane, butanes, condensates (pentanes plus), and non-energy components such as nitrogen, carbon dioxide, hydrogen sulfide and helium. Figure 1.4, illustrates the different components of raw natural gas.
Figure 1.4: Raw Natural Gas Composition
Source: Canadian Centre for Energy Information
5 Ibid.
July 2012
6 Canadian Energy Research Institute
Natural gas as found in the reservoir can be found in many forms including:
- Rich or wet gas, which is rich in natural gas liquids - Lean or dry gas, which has a low liquids component - Sour gas which contains hydrogen sulfide (H2S) - Sweet gas, which is free of hydrogen sulfide - Acid gas, which has a high carbon dioxide (CO2) content - Associated gas, which is produced with crude oil, and; - Solution gas which is dissolved in crude oil and it is produced when the oil is produced
It is important to keep these different types of gas in mind as they dictate the amount of by- products that can be extracted from the gas (as in the case for liquids-rich gas), but also the amount of treating needed to clean up the gas (hydrogen sulfide, and carbon dioxide as an example) to make it suitable for pipeline transportation and end-use.
The typical composition of the raw gas is about 70 to 90 percent methane, with a NGLs (ethane, propane, butanes, and pentanes plus) content of between zero and 20 percent, with the remainder being other components. Figure 1.5 displays the composition of two different types of gas for reference purposes.
Figure 1.5: Sample Raw Gas Compositions
Source: CERI
Most of the non-methane components in the raw natural gas need to be removed from the gas before it can be sold. This removal processed is primarily carried at field processing plants. Gas leaving the plants must meet rigid quality specifications to make it suitable for end-use markets, as well as pipeline transportation. Sales gas refers to raw natural gas which has been processed and is suitable for end uses such as heating. This is also known as residue or marketable gas.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 7
Crude Oil Crude oil is another source of natural gas liquids. Crude oil is usually classified as light, medium, and heavy. Light crudes tend to have a high paraffin to naphthenes and aromatics ratio, and since they have high proportions of naphthenes, they tend to have a higher content of the lighter paraffin hydrocarbons (light ends). Heavy crude on the other hand has a high ratio of aromatics to naphthenes and paraffins, thus indicating that the ratio of lighter hydrocarbons is lower. Figure 1.6 below provides the sample composition for two types of Canadian crudes.
Figure 1.6: Canadian Crude Oil Samples, Light versus Heavy
Source: crudemonitor.ca, CERI
Natural gas liquids are extracted from crude oil during the refining processes and are mainly composed of propane and butanes.
Natural Gas Liquids in North America Since both natural gas (primarily) and crude oil are sources of natural gas liquids, therefore natural gas and crude oil reservoirs and basins across North America provide an indication of where the liquids are found. While it is beyond the purpose of this report to go into the geosciences and the details on where these liquids are found and how that is determined, the following maps provide some visual representation of where the liquids are available.
July 2012
8 Canadian Energy Research Institute
Figure 1.7: North American Natural Gas Liquids Fairways
Source: US Energy Information Administration (EIA), modified by CERI
Figure 1.8: Natural Gas Liquids in the WCSB and Alberta
Sources: University of Regina Plains Research Centre, Alberta Energy Resources Conservation Board (ERCB), modified by CERI
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 9
Natural Gas Liquids: Extraction Processes and Marketing In order to extract the natural gas liquids entrained in both natural gas and crude oil, processing facilities are necessary. Figure 1.9 provides a simplified flow chart of the steps needed in order to get from the hydrocarbon reservoirs to usable products.
Figure 1.9: From Hydrocarbons to End Products
Source: CERI
Natural Gas Processing One of the most complex processes where the liquids are produced is that of natural gas processing, which is illustrated in Figure 1.10. Processing is done for the purpose of treating the gas to make it suitable for sale as well as, to remove any impurities to meet environmental and safety standards. Further, NGLs and other valuable by-products are separated from the stream in order for the gas to meet pipeline specification and in order to obtain value-added associated with the sale of such by-products.
Raw natural gas, when produced, is gathered and compressed (when needed) in order to be transported from the wellhead to the field processing facilities. At the field facilities, various processes take place including the separation of oil (if present) and gas, the removal of condensate, dehydration to get rid of water in the stream, as well as the removal contaminants and impurities such as hydrogen sulfide and carbon dioxide, nitrogen extraction, as well as natural gas liquids extraction. Usually, natural gas liquids are recovered as a mix which is then fractionated (broken into its individual components) at fractionation facilities or fractionators.
As seen in Figure 1.10 some of these processes can occur either at the field or plant level, depending on the complexity of the field processing facilities.
July 2012
10 Canadian Energy Research Institute
Figure 1.10: Natural Gas Processing
Source: EIA6 and Petrostrategies
6 EIA, Natural Gas Processing: The Crucial Link Between Natural Gas Production and its Transportation to Market
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 11
Natural gas liquids separation is an important process in the context of this report. This process can occur either at the field or at centralized facilities. The purpose of this process is to extract the liquids from the gas stream as they usually have a higher value as separated products than if left in the stream. The value of the liquids left in the stream is equivalent to the value of additional heating content provided by each component in the stream as natural gas is usually priced on its heat content rather than its volume.
Liquids are first removed as a mix which is known as an NGL mix, raw make, or y-grade mix. The makeup of the mix will depend on the technology being used to extract them. Generally speaking there are two main extraction technologies, one which makes use of the absorption method where absorbing oil is used to extract the liquids from the gas stream, and one which makes use of cryogenic turbo expanders which drops the temperature to really low levels (cryogenic temperatures, well below 1000C) in order to recover the liquids from the stream. The absorption method is typically used in older or smaller plants as well as in situations where the higher costs associated with cryogenic facilities cannot be justified. The absorption method usually works well to extract the heavier NGLs but not necessarily the lighter ones such as ethane. In that case, a propane plus (propane/ butanes/ pentanes) or C3+ mix might be extracted. On the other hand, due to the use of cryogenic temperatures, turbo expanders are able to recover more of the lighter liquids thus producing an ethane plus (ethane/propane/butanes/pentanes) or C2+ mix. These types of plants are usually known as deep cut facilities as they have the ability to take a deeper cut of the liquids in the stream.
Natural gas liquids fractionators then take the extracted NGL mixes and break them into their individual components. A simplified schematic of the process is provided in Figure 1.11.
Figure 1.11: Natural Gas Liquids Fractionation
Source: National Petroleum Council, provided by Bentek Energy7
7 Natural Gas Liquids (NGLs), Paper #1-13, September 15, 2011
July 2012
12 Canadian Energy Research Institute
The fractionation process works very much like a refinery whereby using the different boiling points of the hydrocarbons in the NGL stream liquids are separated. As an example the de- ethanizer will use the lower boiling point for ethane in order to extract the ethane as a gas from the top of the tower, while a mix of propane, butanes, and pentanes will move from the bottom of the tower on to the next tower, the de-propanizer tower, where the propane will be extracted, and so on until each liquid has been extracted individually. Fractionators are usually large plants which handle NGL mixes from various plants thus taking advantage of economies of scale. They are usually located near demand areas such as those that have petrochemical or refining facilities.
Figure 1.12 summarizes the processes on the natural gas processing side of the supply picture for NGLs.
Figure 1.12: Midstream Processes and Facilities
Source: Tudor, Pickering, Holt, & Co.8
Crude Oil Refining Crude oil refineries produce a variety of refined petroleum products (RPPs). Refineries are both producers and end users of NGLs. Given that different types of crudes have different physical compositions, different types of crudes yield different volumes of liquefied petroleum gases (LPGs).
Sources of LPGs from the refinery process include both the main distillation tower as well the different conversion units such as cokers, catalytic crackers, and hydrocrackers, which are designed to increase the yield of transportation fuels (Figure 1.13). For that reason, the complexity of a refinery will determine the amount of LPGs which are produced. Refineries also produce C5+ (C5 - C12) products such as light and heavy refinery naphthas which are used as petrochemical feedstock.
8 Midstream Update & Primer, November 2008
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 13
Figure 1.13: Refinery Processes, Configuration, and Products
Source: Canadian Petroleum Products Institute (CPPI)
July 2012
14 Canadian Energy Research Institute
Natural Gas Liquids Marketing In general, NGL gathering pipelines transport NGL mixes from field plants to fractionators and processing hubs while product or delivery pipelines move the finished or specification (spec) products from the fractionators to the end-users or to markets. This can also be done via truck, rail, or barge. Truck and rail are generally used to transport non-ethane mixes and spec products, as the low boiling point of ethane makes it uneconomical to transport by means other than pipelines. Truck and rail are mainly used at smaller plants and for areas where pipeline connections are not available. Rail is commonly used to move products in and out of refineries.
The main processing hubs in North America are Fort Saskatchewan, Alberta and Sarnia, Ontario in Canada, and; Mont Belvieu, Texas and Conway, Kansas in the United States. Mont Belvieu is by far the largest processing and trading hub given its integration of processing, refining, petrochemical, and port facilities, and it’s the price setter (for the most part) for NGLs in North America. NGLs markets (demand centres) in North America include Alberta, Ontario, and Quebec in Canada, and the Northeast, Midwest, and Gulf coasts (PADDs I, II, and III) regions in the United States.
An integral part of the marketing and transportation system is storage facilities. These facilities serve to balance seasonal demand fluctuations, as in the case with natural gas. Further, these facilities compensate for capacity constraints on pipelines.
Natural gas liquids need to be stored under pressure in order to maintain their liquid state. Since lighter NGLs require higher pressures, they are more difficult to store. These facilities tend to be located at the inlet of large NGL delivery systems. Both underground and above ground storage facilities are used as seen on Figure 1.14
Figure 1.14: Underground and Above Ground NGLs Storage Facilities
Sources: Oil and Gas Investor, canada.com
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 15
For underground storage facilities, caverns are created using water to dissolve sections of naturally occurring salt formations. Brine stored in a pond is used to displace NGLs volumes out of the caverns. As an example, when the NGLs need to be moved into storage, brine in the cavern is displaced by the NGLs and placed on a pond above ground. Once the liquids are needed and thus must be removed from storage, the brine is injected into the cavern displacing the NGLs and bringing them to the surface where they will be moved on to the transportation medium.
Ethane storage occurs primarily in salt caverns as above ground storage requires highly pressurized vessels which are uneconomic. Propane and butanes can be stored in salt caverns but also in above ground high-pressure steel spheres, cylinders, bullets, or similar structures. Pentanes can be stored at low pressure in tanks similar to those used for gasoline and crude oil.
This concludes the overview section on natural gas liquids. With a basic understanding of what NGLs are, its sources, as well as the extraction processes and marketing dynamics, the next section will bring NGLs into the Canadian context.
First, production volumes will be presented to gain an understanding of the magnitude of the NGLs industry in Canada. Following that supply and demand (S/D) balances will be developed for each liquid, which will allow us to better understand the market dynamics as well as to identify demand sources for each liquid. Pricing is the mechanisms that connect suppliers or producers with end users or buyers, it is the monetary bridge between supply and demand; this will be discussed after the supply and demand balances. Finally, understanding the physical infrastructure that connects supply and demand in Canada will allow us to get a better picture of the NGLs market dynamics.
This will set the stage for Chapters 2 and 3 which present the outlooks and analysis for NGLs supply and demand in Canada and the United States.
Natural Gas Liquids in Canada
Production Total Canadian NGLs9 production including natural gas plants (primary source) and refineries (secondary) averaged 732 thousand barrels per day (mb/d) over the 2000 to 2010 period; the average for 2010 was 681 mb/d.
Of this total, refineries produced volumes in the order of about 60 mb/d (or just under 10 percent of the total) in the form of LPGs (a mixture of mainly propane and butanes), with refineries in Quebec and Ontario being the largest contributors to this category.
9 In the context of this report NGLs include ethane, propane, butanes (both normal and iso-butane), pentanes plus & condensate as well as an NGL mix.
July 2012
16 Canadian Energy Research Institute
Alberta and British Columbia dominate the production of gas plant NGLs in Canada followed by Nova Scotia and Saskatchewan, both of which produce small quantities of NGLs.
In regards to the liquids production breakdown from natural gas processing plants in Canada, ethane accounts for about 35 percent of the total, followed by pentanes plus at about 25 percent, propane at just under 25 percent, and butanes at 15 percent. Alberta produces about 90 percent of the total liquid volumes, followed by British Columbia at about 6 percent, Nova Scotia at 3 percent, and Saskatchewan at 1 percent or less. Therefore, the main focus on the natural gas side of the NGLs supply in Canada will be on NGL volumes produced both in Alberta and British Columbia. However and overall supply and demand picture will be developed for Canada.
As it can be observed in Figure 1.15, there is a high degree of correlation between natural gas production (and processing) and natural gas liquids production.10 Refinery output of LPGs has been relatively steady. Further, while production of natural gas in Canada has declined considerably over the last few years, in general, the decline in overall liquids production has been less severe, an indication that that the natural gas being produced and processed is likely to have a higher natural gas liquids content and/ or that the natural processing plants are increasing extraction efficiencies.
Figure 1.15: Canadian Natural Gas Liquids Production by Source (mb/d) and Raw Natural Gas Production (MMcf/d), 2000 - 2010
Source: ERCB and Statistics Canada Data,11 CERI Analysis
10 72 percent correlation between raw gas production and total NGLs production over the 2000 to 2010 time period. 11 Table 132-0001- Supply & Demand for natural gas liquids and liquefied petroleum gases; Table 131-0002: Supply of natural gas liquids and sulphur products from processing plants; Table 126-0001: Supply and disposition of crude oil and equivalent; ERCB ST-3: Supply and Disposition of ethane, propane, butanes, oil and equivalent, and NGLs; ERCB ST13B: Alberta Gas Plant/ Gas Gathering System Activities.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 17
Gas Plant NGLs Production In regards to the natural gas processing side of the NGLs supply picture, there are various pieces to be taken into consideration. First of all is the production of natural gas; less gas produced means less gas available for processing which will in turn possibly results in lower overall production of natural gas liquids.
As seen in Figure 1.16, raw natural gas production in Canada has been on a steady decline since 2006. On an annual basis production has declined from a peak of over 21,000 million cubic feet per day (MMcf/d) in 2006 to about 18,000 MMcf/d by 2010, or close to a 15 percent decrease.
This decline has been most dramatic in Alberta, where raw gas production has declined from about 17,000 MMcf/d in 2000 to close to 13,000 MMcf/d by 2010, or a 24 percent decrease, a trend that continues. It is also important to keep in mind (in the context of this report) that Alberta is home to the majority of the natural gas processing and liquids extraction infrastructure in Canada, and thus, there are real implications to lower natural gas production and processing levels within the province.
Natural gas prices are also shown in Figure 1.16 for reference purposes. While it can be observed that natural gas prices have fluctuated considerably over the last decade, since 2009 (and up until now) prices have been relatively low, thus discouraging increased production.
On the other hand, low prices are not the only reason for lower production levels but are a major one12. As this situation continues, natural gas producers are likely to slow down drilling for dry gas (gas with no liquids) and accelerate drilling and producing wet gas (liquids-rich gas) in order to improve the economics of their projects.
As this happens, it is possible that in fact, overall gas production increases or remains steady even in a low price environment, but also, the overall natural gas stream produced is likely to be higher in liquids content.
The combination of low gas prices and robust NGLs prices further encourages producers and natural gas processors to increase liquids extraction efficiencies thus resulting in an overall increase in NGLs production volumes.
Note: Statistics Canada separates pentanes plus & (field) condensate (both classified as crude oil and equivalent, or COE) from the rest of the NGLs, the ERCB also uses the same approach. Further, NGLs produced in British Columbia which are fractionated in Alberta are counted as being produced both in British Columbia and Alberta in Statistics Canada’s data. CERI has made adjustments to this data in order to provide a more accurate and reliable picture of NGL production in Canada. 12 Maturity of the WCSB is also a widely quoted explanation for decreasing production volumes out of Western Canada as well as competition with increasing output from prolific US plays which are pushing back Canadian exports out of the US market.
July 2012
18 Canadian Energy Research Institute
Figure 1.16: Canadian Raw Natural Gas Production by Province (MMcf/d) and Average Monthly Natural Gas Price @ AECO ($/GJ), 2000-2010
Source: Statistics Canada and Alberta Department of Energy data,13 CERI analysis
Figure 1.17 illustrates how the natural gas liquids can provide a price per unit uplift to producers in a liquids-rich area of the WCSB as estimated by CERI14
In terms of the overall production of liquids from natural gas processing plants, Figure 1.18 indicates that while the overall production of natural gas has declined significantly over the past decade, the decline in natural gas liquids production volumes is not as pronounced as for natural gas production.
There are various factors contributing to this trend (Figure 1.18), the first one being that the decline is mainly driven by Alberta. Meanwhile, liquids production in provinces such as British Columbia, Saskatchewan, and Nova Scotia has remained relatively steady. Further, natural gas production in British Columbia has increased significantly over the past decade.
13 Table 131-0001: Supply and disposition of natural gas; Alberta Energy: Alberta Gas Reference Price History 14 Keep in mind in the context of Figure 1.17 that the 120 bbl/ MMcf case does not mean that there is no longer methane in the stream, but rather than if the price of methane (natural gas) went to $0/ GJ, the economics of the well are completely carried by the liquids portion of the production stream.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 19
Figure 1.17: Economics of Dry versus Liquids-rich Natural Gas (Montney), Supply Costs, $2011
Source: CERI analysis15
Figure 1.18: NGLs Production (mb/d) and Raw Natural Gas Production (MMcf/d) in Canada, 2002-2010
850 25,000 24,000 800 23,000 750 22,000 21,000 700 20,000 650 19,000 600 18,000 17,000 550 16,000 500 15,000 14,000 450 13,000
kb/d 400 12,000 MMcf/d 11,000 350 10,000 300 9,000 8,000 250 7,000 200 6,000 5,000 150 Pentanes Plus & Condensate (kb/d) Butane (kb/d) 4,000 100 Propane (kb/d) Ethane (kb/d) 3,000 Total Liquids (kb/d) Raw Natural Gas Production 2,000 50 Linear (Total Liquids (kb/d)) Linear (Raw Natural Gas Production) 1,000 - - July July July July July July July July July July July April April April April April April April April April April April January January January January January January January January January January January October October October October October October October October October October October
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Source: Statistics Canada data,16 CERI analysis
15 Assumptions: Supply costs = price needed at NIT to cover all the full-cycle and marketing costs with an assumed 10 percent rate of return on investment and 2.5 percent rate of inflation. Drilling costs data from PSAC estimates for the Montney area, 1 horizontal well, 12 fracs, sweet gas. Liquids mix is a C2+ mix (C2/C3/C4/C5) split 44/17/14/25 respectively. Ethane prices are NIT prices with an uplift estimated by CERI; propane, butanes and pentanes are given as a percentage of WTI at 56, 93, and 110 percent respectively. BC taxes and royalty rates applied. Assumed to be processed transported, fractionated, and sold in the Fort Saskatchewan/ Edmonton Market.
July 2012
20 Canadian Energy Research Institute
Refinery NGLs/LPGs Production Refinery NGLs (or LPGs) production is relatively stable as seen in Figure 1.19. The top chart tells us various facts in regards to refinery NGLs or LPGs production.
First, it shows that both propane and butanes production (about a 50/50 split) have remained stable, with a slight decline trend observed over the last couple of years.
Further, it can be observed that refinery propane production does not exhibit much seasonality compared to refinery butanes, this is the case given that refinery crude runs are fairly stable year round (constant production) but also given that refineries have little use for the propane itself (other than possibly being used as a fuel) and thus is a constant output that must be sold onto the market.
In regards to the production of refinery butanes, seasonality is definitely more important and it is evident in Figure 1.19. As an example, it can be observed that during the colder months of the year (winter), the output of butanes is lower than during the summer months. Often times, during the winter season, refiners can be butanes short (or produce less than needed) and thus must purchase butanes from the gas plants and fractionators in the open market.
During the colder months of the year more butanes are used for gasoline blending and enhancing, while during the summer months, a time in which butanes blending in gasoline is restricted due to vapor pressure and emissions regulations, refineries are more likely to be long (have excess) on butanes and able to sell their product in the market.
Further, the top, center, and bottom charts on Figure 1.19 also indicate that the production of refinery LPGs is a function of refinery crude runs. As it can be observed on the top and center charts, crude runs to Canadian refineries has remained fairly stable over the time period surveyed at about 1,800 mb/d.17 However, it can also be observed that the crude slate (mix of different types of crudes) going into the refineries has been changing slightly over time, with more synthetic crude oil (SCO) and heavy crude oil gaining a share in the slate.
This can be an explanation for the decline in output from refinery butanes and propane as heavier and synthetic (as well as sour) crudes generally have lower percentages of light ends (such as propane and butanes) compared to lighter sweet crudes.18
16 Table 131-0002: Supply of natural gas liquids and sulphur products; Table 131-0001: Supply and disposition of natural gas. 17 On the other hand, production of refined petroleum products has average 2,000 mb/d over the same period. 18 As an example, Alberta’s Medium Sweet Blend (sweet crude) has a total percentage of 5.11 of propane and butanes content, versus Syncrude’s Synthetic (a synthetic crude) at 2.17 percent, and 2.45 percent for Western Canadian Select (WCS) a heavy sour blend. See: www.crudemonitor.ca
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 21
Figure 1.19: Canadian Refinery Production of LPGs (mb/d), Refineries Crude Slate (mb/d & percent) 2000 to 2010, and 2010 Refined Petroleum Product Breakdown (mb/d & percent)
90 2,500
80
2,000 70
60
1,500 50 KB/D KB/D 40 1,000
30
20 500 Total Refinery Production Propane Refinery production 10 Butane Refinery production Total Crude Oil disposition to Canadian Refineries Linear (Total Refinery Production) Linear (Propane Refinery production) Linear (Butane Refinery production) Linear ( Total Crude Oil disposition to Canadian Refineries) - - July July July July July July July July July July July April April April April April April April April April April April January January January January January January January January January January January October October October October October October October October October October October 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 100%
90%
80%
70%
60%
50%
40%
30%
20%
Condensates and pentanes plus charged Crude bitumen charged Synthetic crude oil (light) charged(5) 10% Conventional crude oil (heavy) charged(4) Conventional crude oil (light) charged 0% July July July July July July July July July July July April April April April April April April April April April April January January January January January January January January January January January October October October October October October October October October October October
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Source: Statistics Canada data,19 CERI analysis
19 Table 132-0001- Supply & Demand for natural gas and liquefied petroleum gases; Table 126-0001-Supply and disposition of crude oil and equivalent; Table 134-0001: Refinery supply of crude oil and equivalent; Table 134- 0003: Statistics of refined petroleum products. Note: Light fuel oil includes stove oil, kerosene and tractor fuel; Aviation fuel includes aviation gasoline and turbo fuels; LPGs includes propane, butanes, an propane/ butanes mixes, and; All other products include petro-chemical feedstock, specialty naphtha, petroleum coke, lubricating oil and greases, as well as still gas and other products.
July 2012
22 Canadian Energy Research Institute
Finally, it can be observed (Figure 1.19, bottom) that in 2010 the LPGs fraction of the total produced RPPs (2,016 mb/d) constituted the smallest share of output from refineries in Canada at about three percent.
While refineries are an important source of propane and butanes in Canada, their volumes are, not significant in terms of the overall natural gas liquids supply picture. In fact, refineries only account for about 10 to 15 percent (dependent on seasonality) of the total NGLs production in Canada.
Further, refineries in Canada (up until now) only contribute to the supply of propane and butanes20 and do not necessarily affect the supply picture for both ethane and pentanes,21 which are in turn the largest liquids in terms of output in the Canadian context, as will be discussed below.
Given the limited role of refineries in LPG supply and while an effort has been made to analyze and model the supply of refinery LPGs in Canada, the focus of the analysis presented on this report is on the natural gas processing plant segment of the NGLs supply. Further, potential supply sources of NGLs such as oil sands upgrader’s off-gases will also be discussed.
Potential for Synthetic Gas Liquids (SGLs) Extraction from Oil Sands Upgraders As with refineries producing LPGs there is also an opportunity to produce synthetic gas liquids (SGLs)22 from oil sands upgrading operations. SGLs include the combination of both paraffinic (ethane, propane, and butanes, (C2, C3, and C4)) as well as olefinic (ethylene, propylene, and butylene) liquids entrained in the off-gases stream produced by oil sands upgraders.
Upgrading crude bitumen to SCO is done for the purpose of improving the quality of the crude which results in an increased API gravity (thus making it less dense and less viscous) and by removing impurities and other elements in the raw bitumen, which some refineries are unable to process. The upgraded bitumen (SCO) in turn is not only a product that refineries with simpler configurations are able to process, but also a product that it is easier to transport via pipelines and does not require dilution as does crude bitumen.23
20 Some refineries in the US are capable of producing ethane. Currently, there is a proposal for the Shell Scotford refinery in Alberta to extract ethane volumes (~1 mb/d) from the refinery fuel gas as part of the Government of Alberta’s (GOA) Incremental Ethane Extraction Program (IEEEP). See Table 1.2. 21 Pentanes plus are however used in the refinery market for blending in the gasoline pool, but as we will see, that is a declining and currently almost non-existent source of demand for pentanes plus in the Canadian context. 22 The term SGLs in the context of this report has been adapted from previous analysis by the National Energy Board (NEB) on petrochemical feedstock opportunities from the oil sands. See: NEB: Canada’s Oil Sands: Opportunities and Challenges to 2015, An Energy Market Assessment, May 2004 (Chapter 10), and; Canada’s Oil Sands: Opportunities and Challenges to 2015: An Update, An Energy Market Assessment, June 2006 (Chapter 8) 23 Crude bitumen can be diluted for the purpose of transporting via pipelines with a condensate/pentanes plus type of product or SCO. Bitumen diluted with a pentanes plus mixture is known as dilbit while bitumen diluted with SCO is known as synbit. Over the last few years butanes have increasingly been used for the purpose of bitumen diluent as well.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 23
Upgrader off-gases are a by-product of the upgrading process. It is important to keep in mind that there are three main processes used for upgrading crude bitumen to SCO including coking (thermally cracking heavy and long chain hydrocarbons), catalytic cracking (using a catalyst to break the long chain molecules), and hydro-cracking (using a catalyst and hydrogen to break the long chain molecules) of crude bitumen.
While the input to the processes is somewhat homogeneous (bitumen), the different processes results in a different composition of the off-gases, thus, not all off-gases are the same.
Figure 1.20 illustrates some of the key features of the upgrading operations. It is worth mentioning at this point that with the exception of the OPTI-Nexen Long Lake operation (in situ), most of the existing upgraders are all connected to and have been built in connection to oil sands mining operations. These mining and upgrading projects are known as integrated projects and are characteristic of the legacy oil sands mining projects.
It can be observed (Figure 1.20, top) that there is a clear relationship between the thousands of tons of oil sand being mined and processed on a daily basis (mt/d) and the total bitumen produced (kb/d) by these operations. CERI estimates that between 2008 and 2011 for every ton of oil sands mined and processed, an average of about 0.65 of a barrel of bitumen is extracted. That of course, will vary from operation to operation, and will depend on the grade of the ore being mined and the processing technology.
Figure 1.20 further displays the relationship between the number of barrels of bitumen being sent to be upgraded and the number of barrels of SCO being produced. The average for 2008 to 2011 is estimated at 0.87, thus indicating an average upgrader efficiency of 87 percent. This, once again, will vary according to each upgrading method/ technology.
It must be noted that Figure 1.20 also indicates that the volumes of bitumen going to upgraders is higher than the volumes of bitumen being produced by mining operations. This is the case as some in-situ operations (Suncor’s Firebag as an example) transfer volumes to be upgraded to a mining site with upgrading infrastructure.
Further, Figure 1.20 (middle) displays that there also is a relationship between the numbers of barrels of bitumen processed (as well the number of barrels of SCO produced) and the amount of off-gases being produced. As an example, in regards to the mining operations,24 CERI estimates that for every barrel of bitumen processed in an upgrader about 0.5 thousand cubic feet (mcf) of process gas (or off-gas) is produced.
24 Opti-Nexen’s project has been excluded from this analysis as the numbers obtained from the project as given by the ERCB have wide fluctuations and it is difficult to make a generalization on this unique project. Further, this project uses a closed loop system whereby the process gas is used to fuel the project’s operations to avoid external natural gas purchases.
July 2012
24 Canadian Energy Research Institute
Figure 1.20: Synthetic Crude Oil Production and Capacity by Project (mb/d), Oil Sands Mined & Processed (mt/d), and Off-Gas Production from Upgraders (MMcf/d) and Use (percent), 2008 - 2011
Source: ERCB data25, CERI Analysis
25 ERCB: ST-39 Alberta Mineable Oil Sands Plant Statistics; ST-98: Alberta’s Energy Reserves & Supply/ Demand Outlook.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 25
On the other hand, comparing the off-gas output as a function of a barrel of SCO produced yields a ratio of 0.7 mcf of process gas per barrel of SCO produced. As it can be observed (focusing on the mining projects), with a rise in the production of SCO (from 654 mb/d in 2008 to 863 mb/d by 2011, or a 32 percent increase), there has been an accompanying rise in production of off-gases (from 354 MMcf/d in 2008 to 445 MMcf/d in 2011 or a 29 percent increase).
Last but not least, Figure 1.20 (bottom) displays the breakdown for the produced off-gas usage. For 2011, while about 20 percent (or 89 MMcf/d) of the produced off-gas was sent to two off- gas processing and liquids extraction plants, about 70 percent was used to run the plant’s operations, while the remaining 10 percent was used for the upgrading process itself or flared/ wasted. This remaining 80 percent (about 356 MMcf/d) represents an opportunity for SGLs extraction which is not being utilized at the moment.
The two existing off-gas processing plants include the Williams Fort McMurray Extraction Plant,26 located in the Athabasca area, which processes off-gases from the Suncor upgrader, and Aux Sable’s Heartland Off-gas plant, located in the Industrial Heartland (northeast of Edmonton), which processes off-gases from Shell’s Scotford upgrader. Figure 1.21 provides a visual schematic of Williams’ plants operations in Fort McMurray for reference purposes.
Figure 1.21: Illustration of Williams’ Fort McMurray Extraction Plant
Source: Williams
These off-gas extraction plants have a strategic location advantage and present an opportunity for increased SGLs extraction in the future with Williams’ plant being able to process further volumes from other currently existing upgraders in the Athabasca area such as those owned by Syncrude and Canadian Natural Resources (CNRL), as well as any other planned future upgraders in the area.
26 Williams has recently completed construction of the Borealis pipeline which moves the extracted liquids mix from the Fort McMurray extraction plant an olefinic fractionator in the Redwater (Industrial Heartland) area.
July 2012
26 Canadian Energy Research Institute
On the other hand Aux Sable’s plant can take advantage of its location by sourcing off-gases from Shell Scotford’s upgrader as well as any other future planned upgraders in the Industrial Heartland area.
An example is provided below to illustrate the potential SGLs supply from upgrader off-gases.
According to ERCB data,27 in 2011 Williams’ plant received an average of 87 MMcf/d of process gas and produced about 12 mb/d of a SGLs mix28 (even though they are labeled as diluent naphtha), which indicates that about 138 barrels of liquids are entrained in the off-gas stream (or 138 bbl/ MMcf ratio) 29,30. Williams indicates31 that it currently produces about 15 mb/d of a propane plus (C3+) mix, which would then indicate a bbl per MMcf ratio of 172.
Note however, the above estimate does not include any potential volumes of ethane or ethylene (C2/C2=) entrained in the off-gases, for which Williams estimates it can extract up to 10 mb/d (at current levels of off-gas intake). This in turn would bring up the total bbl/ MMcf ratio to close to 280. Given 2011’s upgrader off-gas production of 445 MMcf/d and assuming a more conservative 250 bbl/ MMcf32 SGLs ratio and no efficiency constraints, the current off-gas production could potentially provide an additional 111 mb/d of liquids. To put this potential volume into context, this volume is in fact equivalent to the volume of pentanes plus (C5+) produced by gas plants and fractionators in Alberta in 2011.33
As oil sands operations continue to grow and crude bitumen continues to be upgraded to SCO in Alberta, upgrader off-gases have the potential to become a significant source of liquids in the future and thus will be considered in our analysis.
This concludes the analysis of the production volumes and potential for further liquids extraction in Canada. The next section will present supply and demand balances for each liquid in Canada, which will enable a better understanding of the end uses for NGLs as well as the significance of imports and exports to balance the NGLs market in Canada.
27 ERCB: ST-39 Alberta Mineable Oil Sands Plant Statistics. 28 Williams’ website states that its Redwater Fractionation Facility, which is fed by liquids from its Fort McMurray plant produces a total of over 12 mb/d of liquids composed of propane (53 percent), propylene (10 percent), normal and iso-butane (16 percent each), and condensate (5 percent). 29 (12*1000)/ 87 = 138 30 The bbl/ MMcf ratio serves as a measure of liquids available in a given gas stream. 31 Various documents: Williams’ website, Investors tab. 32 Alternatively, using an average NGL density conversion ratio of 845 bbl/ MMcf would indicate that the molecular composition of this off-gas stream is about 30 percent (250/845 * 100 = 30 percent). 33 While this example is useful, it is important to remember that the composition of the off-gases coming from different upgraders will have a different composition but also that different extraction plants will have different extraction efficiencies. However these numbers are consistent with CERI’s analysis (below) and were further rectified by analysts from both Williams and the ERCB.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 27
NGLs Supply & Demand (S/D) Balances for Canada and Alberta This section will provide an explanation of both the supply sources and the end–uses (demand) for each of the NGLs in the Canadian context. Further this section will present supply and demand balances for Canada and Alberta based on the available statistics.
Figure 1.22 presents a simplified schematic of the flow of NGLs from supply sources to their different end-uses for reference purposes.
Figure 1.22: NGLs Supply and Demand
Source: National Petroleum Council, provided by Bentek Energy34
Ethane (C2) Following methane, ethane is, generally, the second largest component of raw natural gas, although its content can vary from less than 1 percent to 10 percent or more depending on the gas field. In terms of extraction from the natural gas stream, the most efficient way of extracting methane is by liquefying it at cryogenic temperatures using a turbo expander.
Ethane is colorless, odorless and prior to the 1960’s was burnt along with methane as a fuel. No market for ethane existed at the time in Canada. While ethane extraction is discretionary, that is, not all ethane needs to be extracted from the gas stream to meet pipeline and end user specifications and thus can be left on the stream for its heating value, ethane is extracted in Canada to be used as a feedstock for ethylene production, which is an important building block for the manufacture of chemicals, plastics, and other consumer products.
Figure 1.23 illustrates the different products as outputs of the Canadian petrochemical industry, which for the most part is primarily based on an ethane feedstock. Propane, butanes, and naphtha are used mainly in Ontario as a feedstock, although Alberta’s industry has the ability to use some propane volumes as well.
34 Natural Gas Liquids (NGLs), Paper #1-13, September 15, 2011
July 2012
28 Canadian Energy Research Institute
Figure 1.23: Petrochemical Production in Canada
Source: Industry Canada
When NGLs are “cracked” at high temperatures, they yield ethylene, propylene, butylene and butadiene. During the steam cracking process, when NGLs are briefly heated to very high temperatures, heavy hydrocarbons break down into lighter hydrocarbons.
Ethane is the preferred feedstock for ethylene crackers35 as it yields the highest portion of ethylene compared to other NGLs. Further ethylene (as well as propylene) is regarded as one of the highest value products from the steam cracking process, while other products are considered by-products for which markets need to be found. Ethylene’s main use in Alberta is for the production of polyethylene which is used to produce various forms of plastic films, packaging, and similar products
Ethylene, propylene, butylene and butadiene are regarded as the primary petrochemical building blocks to produce secondary petrochemicals and a greater variety of industrial and consumer products.36 End products include plastics, paints, fiber textiles, pesticides and pharmaceuticals.
Ethane is the backbone of Alberta’s petrochemical industry. Between the increase in ethylene demand from the petrochemical industry and expected flat natural gas production (by some outlooks), Alberta’s ethane supply is currently considered fully utilized. Nearly all of the ethane produced in Canada is extracted at plants located in Alberta while some volumes (<10 percent) are also extracted in British Columbia. Alberta’s extensive series of pipelines and infrastructure to extract fractionate, and transport ethane is discussed in subsequent sections.
35 Note that while the name Ethylene Cracker might imply that the plants crack ethylene, they actually crack ethane as a feedstock to produce ethylene. This should be kept in mind in order to avoid confusion. 36 Ibid.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 29
In regards to production volumes, ethane has taken the brunt of the liquids supply reduction reflecting that the major source of ethane is export straddle (or re-processing) plants at Empress, Alberta,37 whose throughput has declined significantly (from 9,500 MMcf/d in 2002 to 6,500 MMcf/d in 2011, a 32 percent reduction) given the reduction in natural gas export volumes from close to 12,000 MMcf/d in 2002 to close to 7,000 MMcf/d by 2011, or a 42 percent reduction as seen in Figure 3.5.
Meanwhile, Alberta demand for natural gas has increased substantially from an average of close to 2,000 MMcf/d in 2002 to close to 4,000 MMcf/d by the first quarter of 2012 (doubled), driven by consumption in the industrial sector. This can in turn be attributed to the oil sands and power generation industries within Alberta.
This increased local consumption further reduces gas available for exports and therefore volumes processed at export straddle plants.
Ethane supply has declined from a peak of 253 mb/d in 2004 to about 221 mb/d in 2011 (or a 13 percent decline) as seen in Figure 1.24 (top), which indicates a continued shortfall in the ethane supply and (potential maximum) demand balance in Alberta.
While the straddle plants are the largest supply source of ethane (over 70 percent) in Alberta, fractionators (about 20 percent) and field plants (less than 10 percent) also represent important sources of ethane.
These sources of ethane are identified in Figure 1.25 together with the existing ethane gathering (field to process) and delivery (to end-users) system. The infrastructure will be discussed into further detail in another section of this chapter.
In regards to field plants production of ethane in Western Canada, field plants with deep-cut and (de-ethanization) fractionation capacity produce specification ethane which is transported via the Alberta Ethane Gathering System (AEGS) to the petrochemical facilities, while field plants with deep-cut capabilities and no de-ethanization capacity or direct connection to the AEGS produce an ethane plus (C2+) mix that is transported via pipeline to fractionators (including significant volumes from Taylor, British Columbia).
Fractionation feed for ethane plus is restricted to pipeline connections from various fields. These pipelines include Pembina’s Brazeau, Peace, and Northern systems, as well as the Liquids Gathering systems (LGS).
37 Note that while Cochrane is also an important straddle plant located at the east side export point (east gate). However, volumes at Cochrane have remained relatively steady at about 1,700 MMcf/d over the 2002 to 2012Q1 period.
July 2012
30 Canadian Energy Research Institute
Figure 1.24: Ethane Supply and Demand Balance (mb/d) and Natural Gas Production, Export, and Demand Trends in Alberta (MMcf/d), 2002-2Q2012
300 300
275 275
250 250
225 225
200 200
175 175
150 150 KB/D 125 125
100 100 Implied Net Shortfall (Excess) Inventories Used (Built) Fractionation Yield 75 Plant/ Gathering System Process Estimated AB Petrochemical Capacity Total Supply 75 StatsCan AB,BC,SK Ethane Production (CERI ADJUSTED) Total AB Production Total Demand 50 Linear (Total AB Production) 50
25 25
- - July July July July July July July July July July May May May May May May May May May May March March March March March March March March March March March January January January January January January January January January January January November November November November November November November November November November September September September September September September September September September September 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Net Withdrawals (Injecticn) Imports Total Gas Production Estimated Total Supply 25,000 Total Gas Production StatsCan AB Gas Production Total Gas Removal permits Alberta Demand Empress Straddle Plants Gas Throughput Cochrane Straddle Plant Gas Throughput Linear (Total Gas Removal permits) Linear (Alberta Demand) Linear (Empress Straddle Plants Gas Throughput) Linear (Cochrane Straddle Plant Gas Throughput) 20,000
15,000 MMcf/d 10,000
5,000
- July July July July July July July July July July April April April April April April April April April April April January January January January January January January January January January January Octoober Octoober Octoober Octoober Octoober Octoober Octoober Octoober Octoober Octoober 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
5,000 Industrial 4,500 Commercial Residential 4,000 Alberta Demand Linear (Alberta Demand)
3,500
3,000
2,500 MMcf/d
2,000
1,500
1,000
500
- July July July July July July July July July July April April April April April April April April April April April January January January January January January January January January January January Octoober Octoober Octoober Octoober Octoober Octoober Octoober Octoober Octoober Octoober 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Source: ERCB data,38 CERI analysis
38 ERCB ST-3: Supply & Disposition of Gas, Ethane
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 31
Figure 1.25: Ethane Supply Sources and Gathering and Delivery Systems in Alberta, 2012
Source: ERCB39
39 ERCB ST-98: Alberta’s Energy Reserves & Supply/ Demand Outlook
July 2012
32 Canadian Energy Research Institute
As previously stated, overall ethane production has been falling since the middle of the last decade but that trend seems to have stabilized over 2011 and data for the first few months of 2012 indicate a possible turning point for ethane production volumes in Alberta.
However, it is also important to note that as Figure 1.26 indicates, the decline in production volumes has not only been a function of a decline in volumes from the straddle plants but also declines in production from fractionators which have shown an overall declining trend. Field production of spec ethane in Alberta has fluctuated considerably over the last decade, but is showing a stable trend over the last couple of years. This further illustrates the trend of producers trying to get revenues uplift per unit of gas produced at the field level in order to make the economics of natural gas development work.
Figure 1.26: Ethane Production in Alberta by Source, 2002 to Q12012
Source: ERCB,40 CERI analysis
As previously stated, ethane in Alberta is primarily used as a feedstock for ethylene crackers or petrochemical plants which convert raw materials such as NGLs to value-added products such as plastics, textile fibers, chemicals, and other consumer products. CERI estimates petrochemical facilities owned by Dow and NOVA Chemicals in Alberta to have a capacity to process up to 257 mb/d of ethane. Further, small volumes of ethane are used for miscible flood purposes (enhanced oil recovery operations) in Alberta.
Due to its physical properties (high vapor pressure and low boiling point), ethane is only (economically) transported via pipeline. At one point in time, Alberta exported ethane via the Cochin Pipeline system. Currently there are no meaningful imports of ethane into Canada. With supply lower than available capacity, currently, domestic consumption is limited by available supply, that is, the demand is equal to what is produced.
40 ERCB ST-13B: Alberta Gas Plant/ Gas Gathering System Activities
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 33
Alberta’s Incremental Ethane Extraction Policy (IEEP) and Emerging Ethane Supply Sources In 2007, the Alberta Government introduced the incremental ethane extraction policy in order to encourage increased production of ethane from natural gas and other unconventional sources such as oil sands off-gases in Alberta.
The program offers credits to petrochemical facilities which increase ethane consumption above a historical baseline level. These credits can then be transferred from the petrochemical companies to the ethane producers in order to offset royalty obligations from ethane production. Therefore, the total amounts of credits available in a year are equal to the maximum value of ethane royalties expected to be collected in the province.
The maximum credit per facility is capped at $10.5 million. Credits are given for a period of five years from the onset of the increased ethane production.41
Table 1.2 displays the IEEP projects which have been approved, are pending approval, and are on the application process for 2012.
As it can be observed 7 projects have already been approved with an estimated additional 33 mb/d of ethane. Projects pending approval and at the application stage, if approved, have the potential to bring the total number of projects to 17 and the increase ethane volumes to a total of 97 mb/d, which would be more than enough to build a new world-scale ethylene cracker in Alberta. These projects are taken into consideration in our analysis.
In addition to the IEEP projects, which include the construction or modification and installation of new and existing natural processing and liquids extraction facilities, as well as, the extraction of ethane and ethylene from oil sands off-gases, emerging sources of ethane include future ethane imports from both Saskatchewan and North Dakota via the Vantage Pipeline to Alberta.
This pipeline is currently under construction and has received approval from the National Energy Board to import volumes subject to an initial capacity of 40 mb/d of ethane and the ability to expand to 70 mb/d.
Ethane is also expected to be imported into Ontario from the US Northeast. This will allow the existing petrochemical facilities owned by NOVA Chemicals and Imperial Oil in Ontario which currently rely on a mix of sources including ethane, propane, butanes, and naphtha to switch their feedstock to 100 percent ethane.
41 For more information see: http://www.energy.gov.ab.ca/Petrochemical/1349.asp
July 2012
34 Canadian Energy Research Institute
Table 1.2: IEEP Projects by Status and by Company (as of August 2012)
Project Applicant Description (mb/d) Status
Modification of Keyera's Rimbey Gas Plant to optimize Rimbey Ethane Extraction Project Dow Chemicals removal and extraction of C2 5 Approved (2008)
Empress V Deep Cut Project Dow Chemicals Increasing the C2 recovery at the Empress V plant 7 Approved (2008)
Alteration of exisitng infrastructure at Waterton to Shell Waterton Incremental NGL Recovery Project Shell Chemicals increase NGL recovery in Alberta at export point 1 Approved (2011)
Installation of equipement and modfication of existing Musreau Deep Cut Project Dow Chemicals process to maximize C2 extraction and removal 6 Approved (2011)
Installation of various equipment and modification of Scotford Fuel Gas Recovery Project Shell Chemicals processes to extact C2 from Scotford refinery 1 Approved (2011)
Pipeline valve and piping cross-over installations to Hidden Lake Streaming Project NOVA Chemicals direct NGL rich gas Alberta extraction plants 3 Approved (2010)
Installation of equipment enabling capture of ethane Williams Off-Gas Ethane Extraction Project NOVA Chemicals and ethylene out of off-gases 10 Approved (2010)
Installation of equipment and pipeline infrastructure Harmattan Plant Co-Stream Project NOVA Chemicals to optimize extraction and removal of C2 12 Pending Approval (2011)
Installationf of infrastructure capable of capturing Shell Scotford Upgrader Off-gas Project Shell Chemicals ethane off-gases from Scotford Upgrader 3 Open Season (2012) Aggregation of several small investments to improve efficiency at Jumping Pound facility for improved C2 Shell Jumping Pound Project Shell Chemicals extraction 1 Open Season (2012)
Increase the ethane removed from off-gases from 10 to Williams Off-Gas Ethane Extraction Project NOVA Chemicals 17 mb/d 7 Open Season (2012) Construction of a new gas processing plant in NW Alberta which will capture ethane from natural gas AltaGas-Gordondale Deep Cut Project NOVA Chemicals production 4 Open Season (2012) Increase of storage capacity and plant modifications to improve utilization of the existing facility for C2 Judy Creek Ethane Extraction Project NOVA Chemicals extraction 3 Open Season (2012)
Modification and expansion of existing gas plant for Resthaven Facility Phase 1 Dow Chemicals C2 extraction in NW Alberta 7 Open Season (2012)
Modification of exisitng Rimbey gas plant by Rimbey Turbo Expander Project Dow Chemicals installing a turbo expander to improve C2 recovery 20 Open Season (2012) Modification of the existing Saturn Gas plant with the installation of a cryogenic turbo expander to improve Project Turbo (Saturn Plant) Dow Chemicals C2 extraction 8 Open Season (2012) Total Number of Projects 16 Total Volumes 97 By Status Approved 7 33 Pending Approval 1 12 Open Season 8 52 By Company Dow Chemicals 6 53 Shell Chemicals 4 6 NOVA Chemicals 6 38 Source: Government of Alberta data,42 CERI analysis
42 Ibid.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 35
Propane (C3/ C3+) Propane is extracted from the natural gas stream but it is also produced at refineries. As in the case for ethane, Canadian supplies have also seen a decline. However, declines for propane gas plant production have been slower than ethane declines (see Figure 1.27). The main reason for this disparity is that while ethane is dependent on the straddle plant infrastructure, and hence exports for its volumes, for propane, a larger portion of total production is extracted at field plants. Producers motivated by the strong spread between the values of propane in the gas stream compared with propane itself, upgrade facilities to extract an increasing share of the propane at the field level. Therefore, the natural decline in available volumes of gas has been partially offset by improving recovery efficiencies at field extraction plants.
Of the total gas plant produced spec propane in Alberta, about 30 percent is produced at field plants, 15 percent at the straddle plants (mainly Spectra Empress) and the remaining 55 percent is recovered at the fractionators (see Figure 1.28).
Refinery supplied propane is in the range of 30 mb/d in Canada, with Alberta producing about 5 mb/d or 16 percent of the total. Refinery supplied propane is quite stable when compared with gas plant production of butanes.
On a source by source basis for Alberta, straddle plants to some degree but mainly refineries have shown a decline trend in production volumes while field plants volumes have remained stable and fractionators have shown an upswing trend in production volumes. Thus, the decreasing volumes from both refineries and straddle plants have been driving the overall trend. However, as it will be observed in the next chapter, CERI estimates increasing volumes from both field plants and fractionators can turn this trend around in the near future.
The Canadian propane market is supply long meaning there are net volumes available for export as seen in the supply/demand balance in Figure 1.27. Propane exceeding local requirements is exported to the US. Domestic demand has been rising slowly showing a one percent growth rate since 2005. This trend is also apparent in Alberta. However, exports have declined significantly reflecting the reduced supply available in Canada. Demand in Canada has been about 90 mb/d over the 2000 to 2010 time period. The supply and demand balance figure shows that in 2009, 63 percent of the propane produced in Canada was exported to the US where it used mainly for heating purposes. There are only minor imports of propane into Canada.
Of the available 102 mb/d in Canada, about 5 percent was used in the production process while about 15 percent was used as non-energy input for example as a petrochemical feedstock. The remaining 80 percent of propane consumed in Canada is used for energy (heating and fuel) with the industrial sector accounting for 47 percent of the total energy use, followed by the commercial sector at 26 percent, and the residential, transportation, and agriculture sectors accounting for the remaining 37 percent of propane for energy use.
July 2012
36 Canadian Energy Research Institute
Figure 1.27: Propane Supply and Demand in Canada, 2000-2010, Supply and Demand Balance and Propane Production in Alberta, 2002-2011 (mb/d)
Imports Gas plant production Refinery production 300 Total supply Alberta Propane (kb/d) Exports Total domestic demand Linear (Alberta Propane (kb/d)) Linear ( Exports)
250
200 kb/d 150
100
50
- May May May May May May May May May May May January January January January January January January January January January January September September September September September September September September September September September 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Production 160 Exports 100 Imports 1 Inter-regional transfers - Stock variation 3 Inter-product transfers - Other adjustments 27 Availability 90 Refined petroleum products 10 Net refinery produced liquefied petroleum gases (LPG's) 22 Net supply 102 Producer consumption 5 Non-energy use 17 Energy use, final demand 81 Total industrial 38 Total mining and oil and gas extraction 26 Total manufacturing 10 Construction 2 Total transportation 8 Road transport and urban transit 8 Agriculture 5 Residential 10 Public administration - Commercial and other institutional 21 - 50 100 150 200 kb/d Inventories Used (Built) Imports Fractionation Yield Plant/ Gathering System Process 250 Refinery Process Total Supply Total Production Gas Plants Production StatsCan AB Propane Production (Gas Plants & Ref.)(C3 & C3+) Alberta Demand Total Removed from the Province ERCBST98 Propane (C3 & C3+) Linear (Alberta Demand) Linear ( Total Removed from the Province ) 200
150 kb/d
100
50
- July July July July July July July July July July April April April April April April April April April April April January January January January January January January January January January January October October October October October October October October October October 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Source: ERCB and Statistics Canada data,43 CERI Analysis
43 ERCB ST-3: Supply & Disposition of Propane; ERCB ST-98: Alberta’s Energy Reserves & Supply/Demand Outlook;Table 131-0002: Supply of natural gas liquids and sulphur products; Table 132-0001- Supply & Demand for natural gas and liquefied petroleum gases; Table 128-0012: Supply and demand of natural gas liquids. Note: Volumes in the top chart include propane plus (C3+) and specification (spec) propane (C3) volumes together as presented by Statistics Canada data, volumes in the bottom chart are for spec propane only as presented by the ERCB ST3. Statistics Canada’s number is included in the bottom chart for reference purposes. Further, a discussion with staff members from the ERCB confirmed that volumes published in the ERCB ST98 publication for propane, pentanes, and butanes supply include both spec and mixed product. When these numbers are compared with Statistics Canada’s data, it is evident that the given volumes are for spec and mixed product together. This should be taken into consideration for propane, butanes, and pentanes plus numbers.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 37
Propane exports (as well as local demand) exhibit a very strong seasonal shape. Propane is used as a heating fuel in northern US states. Demand for propane is much stronger in the winter than in the summer. The majority of Canadian propane exports are delivered to PADDs I and II. Figure 1.27 demonstrates that winter exports tend to be more than double summer exports.
Figure 1.28: Propane Production in Alberta by Source, 2002 to Q12012
Source: ERCB,44 CERI analysis
Butanes (C4/ C4+) Butanes production in Canada has remained relatively stable around the 130 mb/d mark, with a slight declining trend.
Gas plant production accounts for about 100 mb/d (or 77 percent) of total butanes production. Refinery production has been quite stable at about 30 mb/d with imports increasing in the last couple of years. Alberta refineries account for about 14 mb/d of butanes from refineries production, or 47 percent of the total.
Alberta has seen an increase in demand for butanes over the last couple of years as butanes are being increasingly used for diluting crude bitumen for transportation purposes. Over the 2011 to Q12012 period an average of 20 mb/d were being used for this purpose.
This trend, together with increased NGLs production in the US has resulted in overall declining butanes exports from the province.
44 ERCB ST-13B: Alberta Gas Plant/ Gas Gathering System Activities; ERCB ST-3: Supply & Disposition of Propane
July 2012
38 Canadian Energy Research Institute
Figure 1.29: Butanes Supply and Demand in Canada, 2000-2010, Supply and Demand Balance and Butanes Production in Alberta, 2002-2011 (mb/d)
250 Imports Gas plant production Refinery production Total supply Alberta Butane (kb/d) Total domestic demand Exports Linear (Alberta Butane (kb/d)) Linear ( Total domestic demand) Linear ( Exports) 200
150 kb/d
100
50
- May May May May May May May May May May May January January January January January January January January January January January September September September September September September September September September September September 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Production 98
Exports 28
Imports 9
Inter-regional transfers -
Stock variation 2
Inter-product transfers -
Other adjustments 16
Availability 61
Refined petroleum products 33
Net refinery produced liquefied petroleum gases (LPG's) 19
Net supply 48
Producer consumption 4
Non-energy use 44
Energy use, final demand -
- 20 40 60 80 100 120 kb/d
Source: ERCB, Statistics Canada,45 CERI Analysis
45 ERCB ST-3: Supply & Disposition of Butanes; ERCB ST-98: Alberta’s Energy Reserves & Supply/ Demand Outlook; Table 131-0002: Supply of natural gas liquids and sulphur products; Table 132-0001- Supply & Demand for natural gas and liquefied petroleum gases; Table 128-0012: Supply and demand of natural gas liquids.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 39
In regards to production on a source by source basis for Alberta, similar to propane production trends, straddle plants to some degree but mainly refineries have shown a decline trend in production volumes while field plants and fractionators have shown an upswing trend in production volumes. Thus, the decreasing volumes from both refineries and straddle plants have been driving the overall trend (Figure 1.30). However, CERI estimates (Chapter 2) that increasing volumes from both field plants and fractionators can turn this trend around in the near future.
The overall Canadian market for butanes is balanced by the combination of exports and imports. Exports have averaged 32 mb/d over the 2000 to 2010 period, while imports have averaged 8 mb/d as seen in the supply/demand balance in Figure 1.29. During that period exports have shown a decreasing trend while imports have shown an increasing trend. Domestic demand for butane has hovered around 98 mb/d over the period in question. However, an upwards trend is apparent over the last few years, driven by Alberta’s demand.
Figure 1.30: Butanes Production in Alberta by Source, 2002 to Q12012
Source: ERCB,46 CERI analysis
As seen in the supply demand balance for 2009, all butane used in Canada was classified as being used for non-energy purposes. That reflects on the use of butanes as a petrochemical feedstock (only in eastern Canada), as well as the use by refiners for gasoline blending across Canada, but also on the increasing use of butanes in Alberta as a crude bitumen diluent.
With regards to emerging demand sources for LPGs (propane/butanes) in Canada, service companies have considered using LPGs for fracking oil and gas well stimulations as a substitute for water, while oil sands SAGD operators have considered the use of LPGs as solvent to increase recoveries. These new demand sources create opportunities for LPGs producers in Canada.
46 ERCB ST-13B: Alberta Gas Plant/ Gas Gathering System Activities; ERCB ST-3: Supply & Disposition of Butanes
July 2012
40 Canadian Energy Research Institute
Pentanes Plus & Field Condensate (C5+) Pentanes plus and field condensate are primarily produced in Alberta, while some small volumes are produced in British Columbia, Nova Scotia, and Saskatchewan.
Production of pentanes plus in Canada has averaged 153 mb/d over the 2000 to 2010 decade, showing a relatively flat but declining trend. Meanwhile, field condensate production has averaged 23 mb/d over the same time period, showing a positive trend drive by production in Nova Scotia and British Columbia.
On a source by source basis for Alberta, the declining production trend has been driven by declines in production levels at the field plant level. While there have been increases in field condensate volumes, straddle plant volumes of pentanes plus, and more importantly fractionator production levels, these increasing volumes have failed to offset the declines from the field plants which are by far the main source of pentanes plus (see Figure 1.31, bottom).
This trend can be explained by two factors, one is in fact, lower production levels of natural gas, but given that pentanes plus is the most valuable of the liquids, thus creating the incentive to maximize extraction, declining volumes must be related to diminishing availability in the produced gas.
Currently, the main use for pentanes plus and field condensate in Canada is for diluting crude bitumen. This is needed in order to upgrade the viscosity of the bitumen to be able to transport it on pipelines to markets. However, these liquids are also used in the refinery market as they are used for blending purposes in the gasoline pool. That is, in fact, the main use for pentanes plus and condensate in the United States.
As it can be observed in Figure 1.31 (top and middle) the refinery market for pentanes plus has decreased from about 40 mb/d at the start of the decade to being almost non-existent by the end of the decade. This trend has in fact coincided with lower volumes of crude bitumen being delivered to Canadian refineries.
On the other hand, the increased production of crude bitumen in Canada has driven the demand on the diluent side of the market. This also indicates that as production of crude bitumen increases and domestic use (deliveries to Canadian refineries) decreases, more and more volumes are being exported.
The required volumes of pentanes plus and condensate have significantly outpaced the production capacity in Canada since about 2004, making it necessary to import diluents from abroad. By 2010, an estimated 260 mb/d of diluent were required while total domestic production was about 160 mb/d indicating that close to 40 percent (100 mb/d) of the required diluent must have been imported. This trend is bound to continue as increasingly produced oil sands volumes are expected to be more of crude bitumen than synthetic crude oil.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 41
Figure 1.31: Canadian Supply/Demand Balance for Pentanes Plus and Condensate, Condensates and Pentanes Plus Charged to Canadian Refineries (mb/d), 2000-2010, and Pentanes Plus Production in Alberta by Source, 2002 to Q12012
Source: ERCB and Statistics Canada data,47 CERI Analysis
47 ERCB ST-3: Supply & Disposition of Crude Oil & Equivalent; ERCB ST-13B: Alberta Gas Plant/ Gas Gathering System Activities; ERCB ST-98: Alberta’s Energy Reserves & Supply/ Demand Outlook; Table 126-0001-Supply and disposition of crude oil and equivalent; Table 134-0001: Refinery supply of crude oil and equivalent
July 2012
42 Canadian Energy Research Institute
As demand has increased for this commodity and, given the local shortage as well as its similarity to light crude oil, pentanes plus have generally commanded a price premium over the price of light crude oil over the last few years (this will be further discussed in the pricing section).
Oil sands producers will find themselves increasingly looking for sources of diluents from as far away as the Asia-Pacific and South American regions in order to be able to move their product to market as seen on Figure 1.32.
Figure 1.32: Increasing Diluent Needed for Oil Sands Operations
Source: Cenovus Energy Corporate Presentation
Alternatively some producers will consider alternative transportation options such as rail (for long distances) and truck (short-haul) which might not require the use of diluents, while others will consider on-site upgrading depending on market conditions and economics.
NGL Raw Mix (Y-Grade) NGL raw mix, also known as Y-grade is an important part of the supply and demand picture for NGLs in Canada. While some field extraction facilities have the ability to not only extract liquids from the natural gas (which are recovered as a mix) as well as the ability to separate each liquid from this mix into purity or specification product, a considerable number of plants only have the ability to extract a mix. This mix is then sent by pipeline, rail, or truck to fractionators within the province or exported out of the province as an NGL mix.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 43
It is important to make the distinction between the mix and purity products.
As an example, Statistics Canada data, as well as supply data from the ERCB ST-98 report, only reports data for ethane, propane, butanes, and pentanes plus which are equivalent to the sum of the liquids produced in a province. Since we know that not all liquids produced are being produced as purity products, it must therefore be the case that mixes and specification products are summed together. Knowing this, allows us to estimate the components of each liquid in the available NGL mix.
This NGL mix issue is not only related to Alberta, but also applicable to British Columbia. As an example, the Taylor plant in British Columbia produces in excess of 20 mb/d of an NGL mix (mainly ethane) which is shipped on the Peace pipeline system to the fractionators in Fort Saskatchewan, Alberta. If the produced ethane in the mix in British Columbia is added to the ethane being produced in the fractionators, then the volumes are being double counted.
Figure 1.33 displays the supply and demand balance picture for Alberta. The first thing to take note of is that production volumes of NGL mix from the natural gas system plants in Alberta has been on a decline trend that seems to have leveled over the last few months.
The imports wedge in the top chart corresponds to an NGL mix moving from British Columbia’s field and straddle plants to Alberta fractionators. Also, drawdown of inventories account for a small part of the supply.
On a source by source basis, the main source of NGL mix is field plants followed by straddle plants. The overall production decline trend can be seen as being driven by both declines at the field level primarily but, also by declines at the straddle plant level. This trend has stabilized over the last couple of years and has in fact shown an upswing over the last couple of months.
On the demand side, 30 percent is exported, primarily to Ontario with small volumes going to the US Midwest. In Ontario, these liquids are fractionated into specification products at the Plains Fractionator in Sarnia. The remaining 70 percent of this mix gets processed or used in Alberta, with a small fraction being delivered to injection facilities and the vast majority being delivered to the fractionators for processing into specification products.
A trend which is apparent is that while overall production volumes of the NGL mix have decreased over time in Alberta, the yield of products from fractionators in Alberta has remained relatively steady. This is the result of a combination of two trends, increasing imports of an NGL from British Columbia into Alberta as well as local NGL mixes being processed in the province in order to capture the value of the liquids. Available export volumes have been squeezed out to compensate.
This difference between NGL specification products versus mixes as well as the export dynamics are considered in our analysis.
July 2012
44 Canadian Energy Research Institute
Figure 1.33: Alberta Supply/ Demand Balance for Natural Gas Liquids Mix, and NGL Mix Production in Alberta by Source (mb/d), 2002 – Q12012
Source: ERCB48, CERI Analysis
48 ERCB ST-3: Supply & Disposition of Natural Gas Liquids; ERCB ST-13B: Alberta Gas Plant/ Gas Gathering System Activities
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 45
NGLs Pricing & Economics Having established what NGLs are, how they are extracted, and how they fit in the demand and supply picture in Canada, this short section briefly explains some principles of NGLs prices. The last section will be an overview of the NGLs related infrastructure in Canada.
NGLs prices are complex and in some situations not necessarily transparent (ethane). Prices for NGLs are at the crossroads of natural gas (which usually serve to set the price floor) and crude oil and refined petroleum products (which usually serve to set the price ceiling) and their values as a petrochemical feedstock.
If NGLs are not extracted from the gas stream, the energy associated with the NGLs is sold for the same value of natural gas. If the price of a given liquid (as it is periodically the case for ethane) is equal to or lower than the natural gas price, there is no incentive to extract the liquids as the extraction costs are not recovered. For this reason, natural gas serves as the price floor for NGLs.
Refined petroleum products such as heating oil can be used as substitutes in the heating market for other products such as propane and butanes. Alternatively, other refined petroleum products such as refinery naphtha can be used in the petrochemical market as a substitute for NGLs. Since crude oil is the feedstock required for producing petroleum products, as in the case for natural gas liquids, the price of the refined products must be enough to cover the price of the feedstock (crude oil) plus the processing (refining) and a margin. Since RPPs will tend to have prices above crude oil and are used as substitutes for NGLs, they are a good indication of the price ceiling for NGLs. Prices are also affected by seasonality, weather, and economic conditions.
While these principles are very general and serve as a guideline for understanding NGLs prices, it is also important to understand that the price for each liquid is set within its own end-use market based on the value of end products as well as substitutes in the case for petrochemical feedstock.
In general, North American NGL prices are set by the Mont Belvieu market in Texas as this is the largest trading hub and market. Mont Belvieu is located in the US gulf coast, giving this trading hub a strategic location as it has access to worldwide supplies and it also has major storage, transportation, and processing facilities including gas plants, fractionators, refineries, and petrochemical facilities. If it was the case that substantial volumes of Canadian NGLs were directly exported overseas, then Canadian prices would also be affected by world prices. Currently, that is not the case.
Other NGLs market hubs in North America include Edmonton/Fort Saskatchewan, Alberta and Conway, Kansas (both of which serve the Midwest market) as well as Sarnia, Ontario, which together with Mont Belvieu serve the northeast market.
July 2012
46 Canadian Energy Research Institute
Figure 1.34 presents some of the pricing dynamics of Canadian NGLs both on an energy and volumetric basis.
Figure 1.34: Canadian NGLs pricing $/GJ (top) and $/ bbl (bottom)
Sources: Alberta Department of Energy data, EIA data, MJ Ervin & Associates data, CERI analysis
The top chart illustrates various items which are worth noting. As discussed above the price floor is set by the price of natural gas, which is the cost of the feedstock required to extract the liquids. The rack (wholesale) price for Canadian furnace oil has been used in this chart as the price ceiling for NGLs given the price discount trends that West Texas Intermediate (WTI) crude has exhibited over the last few months.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 47
In regards to ethane, it should be noted that it is priced at the same level as natural gas on an energy basis. This would however indicate that there would never exist an incentive to extract ethane from the gas stream as the value would be the same as the natural gas (costs) thus not being able to cover extraction, fractionation, and transportation (marketing) costs to be able to take the product to the end user.
Since there are only two major buyers of ethane in the province (NOVA Chemicals and Dow Chemicals), they hold purchasing power and can negotiate prices with each producer individually, thus ethane pricing is different for every producer. While the commodity component of ethane may only attract gas values as published by the Government of Alberta reference prices49, buyers must pay facilities owners to compensate for use of the infrastructure required to extract and market ethane.50 As it is known that the price of ethane paid to a producer must cover the feedstock (natural gas) costs, extraction, and marketing costs including fractionation and transportation, CERI has developed estimates for the price of ethane on a per barrel basis which are presented on the bottom portion of Figure 1.34 (bottom).51
In regards to propane and butanes, it can be observed that they track crude oil prices both on an energy and volumetric basis. Pentanes plus, due to their similarity to crude oil follow the price of crude oil quite closely and in fact, have in various occasions commanded a premium over crude given their high demand for used as a diluent in oil sands operations.
Figure 1.35 displays the prices of NGLs in Canada as a percentage of crude oil prices (top). The price for pentanes as a percentage of the price of crude oil has remained stable over the last decade while the price of butanes exhibits an increasing trend. Propane prices tend to fluctuate more. In fact, propane prices are currently at its lowest levels in relation to crude prices over the time frame in Figure 1.35. This can be the case as the market is currently in a surplus situation.
The difference between the price of natural gas and the price of crude is an important consideration. As most liquids (except for ethane) tend to follow crude oil prices, thus the higher the spread (on an energy basis) between the prices of natural gas and crude oil is, the higher the incentive to extract the liquids. This is illustrated on Figure 1.35 (middle).
49 Reference prices are the government’s assessment of market prices for royalty purposes and should be used as a reference only. They do not represent final sale prices as that would depend on individual deals and negotiations in particular for illiquid markets. They are however an indication of market prices. 50 This is explained in various investor information documents available both from buyers such as NOVA Chemicals as well as sellers such as Altagas or Inter Pipeline Fund. These documents are generally called Annual Information Forms and explain the operations and business of a given company. These are publicly available documents. 51 These price estimates are consistent with price estimates developed by First Energy Capital as well as costs estimates for Alberta ethane based ethylene presented by NOVA Chemicals, CMAI, and Purvin & Gertz at CERI’s petrochemical conferences. Further, the methodology has been developed by reviewing documents such as annual information forms from ethane producers such as Altagas and Interpipeline Fund.
July 2012
48 Canadian Energy Research Institute
However, in a situation where the price of gas is above the price of gas on an energy basis, then the NGL prices will follow natural gas prices as the price needs to be higher than natural gas to justify extraction costs (as seen on Figure 1.34).
Figure 1.35: NGLs Prices as a Percentage of Crude Oil (top), NGLs Gross Frac Spread (middle), and Crude Oil Price to Natural Gas Price Ratio (bottom)
Sources: Alberta Department of Energy data, EIA data, ERCB data, CERI analysis
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 49
Figure 1.35 (bottom) also illustrates the gross frac spreads which is the difference on an energy basis between natural gas prices and the extracted liquids’ prices. This serves as gauge for the margins obtained by NGLs producers. However, extraction and marketing costs also need to be considered (net margins).
Last but not least, Figure 1.36 illustrates how the market for a given liquid is balanced (top) as well as the different type of processing arrangements available to producers from midstream or processing companies.
Figure 1.36: NGLs Economics (top) and Common Gas Processing Contract Structures52
Source: Tudor, Pickering, Holt, & Co.53
52 For more publicly available information on the economics of NGLs and Petrochemicals visit RBN Energy’s Blog. Example: Let’s Get Cracking – How Petrochemicals set NGL Prices – Part IV http://www.rbnenergy.com/lets-get-crackin-petrochemicals-ngl-prices%E2%80%93pt4
July 2012
50 Canadian Energy Research Institute
This concludes our discussion on NGLs pricing and economics, the next section will discuss the physical NGL infrastructure with a focus on Canada.
NGLs Infrastructure in Canada The NGL infrastructure in Canada, particularly in Alberta, is complex. It includes gas processing plants (field plants), refineries, straddle plants, fractionation facilities, as well as a network of pipelines for gathering and delivery, and various storage facilities and petrochemical plants. Figure 1.37 illustrates Canada’s complex NGL network.
Figure 1.37: Major NGL Infrastructure in Canada
Source: National Energy Board54 While there is some production of NGLs at the Point Tupper, Nova Scotia facility which is connected to the Sable Offshore Energy Project (SOEP), Western Canada accounts for the majority of NGL supply. The petrochemical industry is located, primarily in Fort Saskatchewan and Joffre, Alberta and Sarnia, Ontario.
The following section provides an overview to the infrastructure in Canada, with a focus on Alberta and Sarnia, Ontario. This section will briefly outline Canada’s extensive infrastructure, with a focus on field plants, straddle plants, and fractionation plants, gathering pipelines, main delivery systems, and petrochemical plants.
53 Midstream Update & Primer, November 2008 54 Canada's Energy Future: Infrastructure Changes and Challenges to 2020 - Energy Market Assessment
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 51
Field Plants, Straddle Plants, Fractionation Facilities and NGL Gathering Pipelines Natural gas liquids are initially extracted from natural gas at field plants and straddle (or re- processing) plants. There are almost 800 active plants in Canada and over 600 of these are located in Alberta, including nine fractionators and eight straddle plants (Table 1.3).
Table 1.3: Natural Gas Processing Plants in Canada
Gas Processing Plants in Canada Province # Alberta 654 British Columbia 86 Saskatchewan 25 Ontario 1 Nova Scotia 1 Total 767 Source: ERCB data, BC Ministry of Energy Mines and Petroleum Resources (BCMEMPR), Oil & Gas Journal, CERI analysis
NGL production in Canada began in the 1950s. At this time propane, butane and pentanes plus were removed from the gas stream and sold and used as heating fuel or, in the case of butane and pentanes plus, as motor fuel.55 Ethane, on the other hand was left in the gas stream, as no market for it existed. As the conventional natural gas market evolved in Canada, so did the NGL infrastructure, including the construction of petrochemical plants and extraction facilities which began to take advantage of the abundant ethane and other NGLs.
Straddle plants are plants located on the main natural gas transmission pipeline systems (straddles) which process gas that has already been processed at the field level (re-processing). Since most of the heavier liquids (pentanes, butanes, and propane) are extracted at the field level, these plants main function is the removal of ethane, thus making them the current major suppliers to the petrochemical industry.
There are 15 straddle plants that extract incremental amounts of ethane and other NGLs from natural gas in western Canada. Figure 1.38 lists the 14 Straddle Plants in Alberta (as of 2011) which have a combined capacity of over 13,000 MMcf/d.
The Younger NGL plant, located in Taylor, British Columbia, approximately 15 kilometres from Fort St. John, is also an important straddle plant. The plant supplies local markets as well as fractionation plants near Edmonton. This plant is partly owned by AltaGas and Pembina Pipelines.
55 Louise Gill and Paul Mortensen, “Canadian NGLs Market Outlook 2000-2010”, CERI, pp. 5
July 2012
52 Canadian Energy Research Institute
Figure 1.38: Alberta Straddle Plants and Locations
# Plant Name Operator Ownership Estimated Capacity (mmcf/d) 1 Edmonton Ethane Extraction Altagas ATCO 51%/Altagas 49% 390 2 Fort Saskatchewan Ethane Extraction ATCO ATCO (100%) 37 3 Golden Spike Ethane Extraction ATCO ATCO (100%) 65 4 Paddle River Gas Plant Keyera Energy Keyera 87%, Pennwest 12%, CNRL 1% 100 5 Villeneuve Ethane Extraction ATCO ATCO (100%) 40 6 Cochrane IPF Inter Pipeline Fund (100%) 2,500 7 Joffre Ethane Extraction Altagas Altagas (100%) 250 8 BP Empress 1 BP BP (67%), Provident (33%) 1,200 9 Provident Empress Provident Provident (67.5%), Devon (10%), Altgas (11.25%), Husky (11.25%) 1,200 10 BP Empress 2 BP Inter Pipeline Fund (100%) 2,700 11 BP Empress 5 BP BP (50%), IPF (50%) 1,100 12 Empress Gas Liquids Joint Venture ATCO BP (35.5%) …. Altagas (7.2%), ATCO (12.2%) 1,100 13 Spectra Empress Spectra Spectra Energy (92%), Provident (8%) 2,400 14 Waterton Gas Complex Shell Canada Shell Canada (100%) 300 Total 13,382
Source: NEB’s NGTL NEXT Application Documents, CERI analysis
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 53
It is important to note here that any facilities that were owned by BP Canada are now owned by Plains Midstream and those that were owned by Provident Energy are owned by Pembina Pipelines.
While various straddle plants are found in and around the Edmonton area the largest straddle plant capacity is located at Empress, on the Alberta-side of the Alberta-Saskatchewan border.
The largest players in the straddle plants segment are Inter Pipeline Fund (5,700 MMcf/d), Spectra Energy (2,200 MMcf/d) and Plains Midstream (1,700 MMcf/d).
Generally speaking Empress straddle plants produce an average of 100 mb/d of ethane, followed by Cochrane at about 50 mb/d, while the Taylor plant produces about 20 mb/d of ethane in a C2+ form which is fractionated in Fort Saskatchewan, and the remainder of the straddle plants can produce between 20 and 30 mb/d of ethane.
In regards to fractionation facilities, key facilities are located in Fort Saskatchewan, Alberta. Various NGL gathering systems connect field processing and straddle plants to this main fractionation centre.
Dow Chemicals and Pembina own fractionation facilities with substantial de-ethanization capacity capable of producing over 70 mb/d of ethane. Further, these fractionators can produce over 90 mb/d of other specification liquids other than ethane. These fractionators are connected to the Peace and Northern pipeline system which deliver ethane in a mixed form from deep-cut processing plants both in northeastern British Columbia and northwestern Alberta. Ethane also moves in a C2+ mix to this location via the Brazeau system in central Alberta.
The main NGL gathering system and associated facilities are displayed in Figure 1.39. As a guideline, pipelines going into the Fort Saskatchewan area (those located west and south of it) are gathering pipelines while those heading east are delivery pipelines.
The main difference is that gathering pipelines feed the fractionators while delivery pipelines provide an outlet and a connection to markets.
Other major fractionation facilities in the area include Keyera’s Fort Saskatchewan and Plains Midstream fractionators with a combined capacity to produce over 70 mb/d of specification propane, butanes, and pentanes plus.
These fractionators are connected to the pipeline systems mentioned above as well as to the Co-Ed (Cochrane to Edmonton) pipeline system which moves NGLs in the form of a C3+ mix from various facilities in central and southwest Alberta including over30 mb/d of NGL mix from the Cochrane straddle plant.
July 2012
54 Canadian Energy Research Institute
Figure 1.39: NGLs Infrastructure in Alberta56
Source: Encana Corporate Presentation Williams owns a fractionator in the Fort Saskatchewan area with capabilities to extract not only NGLs but also olefins such as ethylene, propylene, butylene and condensates, which are sent as a SGLs mix from their Fort McMurray extraction plant (off-gas processing facility). Williams’ operations are illustrated in Figure 1.40.
Fort Saskatchewan area fractionators together with other small fractionation facilities across Alberta have the capacity to produce over 300 mb/d of NGL specification products.
56 Note that while there are various intra-Alberta pipeline systems that deliver diluent to the oil sands areas it is not practical to discuss each one of those here. Further, these systems are described and overviewed in other CERI studies that are related oil sands projects and the related pipeline infrastructure.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 55
Figure 1.40: Map of William Energy’s Alberta Assets
Source: Williams Energy
While Sarnia is the home to a large petrochemical complex, it is also home to a single fractionation facility with a capacity of about 140 mb/d, which is jointly owned by Pembina Pipelines and Plains Midstream. The facility removes NGLs from the Enbridge mainline pipeline system, as well as Kinder Morgan’s Cochin Pipeline system and Shell’s Kalkaska plant.57 The fractionation plant’s products include propane, iso-butane, normal butane and condensate.58
Refineries and Upgraders As of 2011 there were 18 refineries in Canada with a total processing capacity of close to 2,000 mb/d as seen in Figure 1.41. Major refinery clusters are located in Atlantic Canada, followed by Alberta, Quebec, Ontario, with the smallest refining clusters located in Saskatchewan and British Columbia.
Atlantic Canada is home to the Irving refinery located is St. John’s New Brunswick, which is Canada’s largest refinery with a capacity to process 259 mb/d. Alberta’s refineries are located in the Industrial Heartland area with Imperial Oil’s refinery being the largest with a capacity of 190 mb/d. Valero’s Ultramar refinery in Levis (Quebec City) is the largest refinery in Quebec with a capacity of 240 mb/d. Imperial Oil’s Sarnia refinery in Ontario is the largest in the region with a capacity of 120 mb/d.
57 BP Canada, 2005/06 Environmental Statement: Sarnia and Windsor 58 Sarnia-Lambton Economic Partnership, Petrochemical and Refining Complex
July 2012
56 Canadian Energy Research Institute
Figure 1.41: Refining Capacity (mb/d) and Number of Refineries in Canada, by Region, 2011
Sources: Canadian Association of Petroleum Producers (CAPP) data, Canadian Petroleum Products Institute (CPPI) data, Oil & Gas Journal data, CERI analysis
Oil sands upgraders are located primarily in the Fort McMurray (Athabasca) area with some upgrading capacity located in the Industrial Heartland as well. Suncor’s upgrading capacity is by far the largest, followed by Syncrude’s, both of which are legacy integrated mining and upgrading projects.
Table 1.4: Alberta Oil Sands Upgraders
Source: Alberta Energy
NGL Delivery Systems NGL delivery systems connect fractionators, field plants with fractionation capacity, and straddle plants to end-use markets and are designed to deliver primarily spec NGLs.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 57
Alberta Ethane Gathering System The Alberta Ethane Gathering System (AEGS) is a specification ethane only pipeline system that connects field plants, fractionators, and straddle plants in the province with Alberta’s petrochemical facilities. Figure 1.42 illustrates the system configuration. The system is owned by Veresen and operated by NOVA Chemicals.
Figure 1.42: AEGS Pipeline System59
Source: National Energy Board Cochin Pipeline Kinder Morgan owns the Cochin pipeline which currently delivers specification propane from Alberta to the US Midwest and Ontario. The pipeline provides connections with the MAPCO system in the US, which leads to Conway, Kansas a major NGL hub.
This pipeline is expected to be reversed by 2014, that is, flow from the US to Alberta, and will provide condensate supplies from the US gulf coast and Midwest to oil sands operations in northern Alberta as illustrated in Figure 1.43
59 Note that Imperial Oil’s Bonnie Glen plant is no longer in operation. Further, Empress’ Straddle plants current ownership is different from that displayed in Figure 1.42. See Figure1.38 for an up to date list of Empress’ plants ownership interests. While this figure might be outdated, it was chosen given its level of detail for reference purposes. Figure 1.25 also illustrates the AEGS system.
July 2012
58 Canadian Energy Research Institute
Figure 1.43: Cochin Pipeline Reversal Project
.
Source: Kinder Morgan
Empress-Kerrobert and Enbridge Canadian Mainline and Southern Lights Systems Enbridge Main-line’s lines one and five provide an outlet for NGL mixes (C3+ only) from the Fort Saskatchewan area to the US Midwest and Ontario. These pipelines also serve as an outlet to the Empress Straddle plants’ non-ethane NGL mixes, which are delivered to the Enbridge system via the Empress-Kerrobert pipeline. Enbridge’s Southern Lights pipeline moves condensate from the US Midwest to Alberta. These pipelines are shown in Figure 1.44 below:
Figure 1.44: Empress-Kerrobert and Enbridge’s Mainline and Southern Lights Pipelines
Sources: BP, Enbridge
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 59
Empress System Pipeline (PTC) Spectra Energy operates the Petroleum Transmission Company (PTC) pipeline which carries both spec propane and butanes from Spectra’s straddle plants at Empress across markets in Saskatchewan and Manitoba. This pipeline is shown in Figure 1.45.
Figure 1.45: Spectra Energy and the Empress System
Source: Union Gas Rangeland Pipeline System The Rangeland Pipeline System is owned by Plains Midstream Canada and has the capability to move NGL mixes, butanes, condensate and various types of crude from the Edmonton area to the Alberta-Montana border where it connects with Plains’ Western Corridor system which spans across the US Rockies and Midwest regions. The Rangeland Pipeline System is displayed in Figure 1.46.
Figure 1.46: Plains Midstream Pipelines
Source: Canadian Energy Pipeline Association (CEPA)
July 2012
60 Canadian Energy Research Institute
Vantage Pipeline The Vantage pipeline project is a high vapour pressure (HVP) pipeline designed to carry up to 40 mb/d of specification or purity ethane from North Dakota’s Bakken formation, across Saskatchewan, to Empress, Alberta with the potential to expand to 70 mb/d. The Vantage pipeline will tie-in to the AEGS system thus providing direct access to Alberta’s petrochemical industry. The pipeline has received regulatory approval from the National Energy Board. It is currently under construction and expected to be commissioned during 2013. Figure 1.47 displays the route of the Vantage Pipeline.
Figure 1.47: Vantage Pipeline
Source: Vantage Pipeline
Alliance Pipeline The Alliance pipeline system (owned by Veresen, and Enbridge) is composed of a high-pressure pipeline which transports liquids-rich gas from various points in the WCSB (and more currently the Bakken formation) to the Aux Sable extraction and fractionation facility in Channahon, Illinois (owned by Veresen, Williams, and Enbridge). The system transports natural gas from northeastern British Columbia, Northwestern Alberta, Southern Saskatchewan, and North Dakota, through Minnesota and Iowa, to Illinois. Figure 1.48 illustrates the high-pressure natural gas Alliance Pipeline.
Alliance pipeline was commissioned in 2000 and it is meant to provide an alternative outlet for marketing liquids outside of the WCSB and into the US Midwest market. Volumes are primarily contracted on a long-term basis with firm capacity estimated at 1,300 MMcf/d while the overall volumes can be as high as 1,800 MMcf/d. In 2011 an average of 1,650 MMcf/d of liquids-rich natural gas were transported on Alliance. A sample of the gas stream components for June 2012 indicates that Alliance’s gas has an average liquid content of 9.2 percent with close to 7 percent corresponding to ethane.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 61
Using 2011’s flow rate CERI estimates that this translates into a total of 68 mb/d of ethane, 20 mb/d of propane, 7 mb/d of butanes, and 2 mb/d of pentanes plus, for a total of 97 mb/d of NGLs moving primarily from the WCSB (with small Bakken volumes) on Alliance to the US Midwest.60
Figure 1.48: Alliance Pipeline
Source: Veresen Corporate Presentation
Ethane extracted by Aux Sable in Channahon is likely to be marketed to petrochemical facilities owned by Equistar Chemicals (LyondellBasell) located in Clinton, Iowa and Morris, Illinois. CERI estimates the ethane feedstock capacity for these plants (based on capacities published by the Oil & Gas Journal) to be above 50 mb/d. It is worth noting that other than a small facility located in Calvert City, Kentucky owned by Westlake Petrochemicals; these are the only petrochemical facilities in the United States outside of the Texas-Louisiana Gulf Coast region.
60 Molecular composition is 6.6 percent ethane, 1.9 percent propane, 0.55 butanes, and 0.14 pentanes plus.
July 2012
62 Canadian Energy Research Institute
Other Transportation Infrastructure Other transportation infrastructure used for NGLs (excluding ethane), as well as crude oil, and chemicals transportation in Canada and in North America includes a vast network of roads and railways. Figure 1.49 illustrates the railway system in North America for reference purposes.
Figure 1.49: North American Railway Systems
Source: Hofstra University, Department of Global Studies and Geography
Petrochemical Plants Petrochemicals are the building blocks for the production of various chemicals, plastics, and consumer products used in our daily lives.
Ethylene and propylene (olefins) are the main building blocks for petrochemical derivatives, while others include butadiene and aromatics such as toluene, xylenes, and benzene.
Olefins are obtained by cracking (high temperature processing) NGLs, naphthas, gas oils, and others. Chemical derivatives are produced from these olefins, which in turn add value to the product created each step along the manufacturing path as seen on Figure 1.50, thus adding incremental value to the economy. In fact moving from ethane to ethylene can add up to two times the product value and so on along the chain. Figure 1.50 further displays some of the economics from producing ethylene from ethane versus propane.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 63
Cracking ethane can yield 81 percent ethylene and 19 percent other co-products, which indicates why ethane is the preferred feedstock for ethylene production.61 Propane yields a higher proportion of propylene and it is thus preferred for this purpose. Figure 1.51 illustrates ethane, propane, ethylene, propylene and their derivative applications.
Feedstock (NGLs) costs are an important consideration for petrochemical plants as they can account for over 70 percent of the operating costs. Thus, feedstock choice, availability and pricing are important issues to consider in the context of the petrochemical industry.
Since various consumer products are made from derivatives, which are produced from olefins, which are produced from NGLs, general economic conditions which drive consumer behaviour as well as the derivatives market have a direct effect on NGLs production and prices.
As previously mentioned, Canada’s petrochemical industry is located primarily in Alberta and Ontario. In Alberta, plants are clustered in Joffre and Fort Saskatchewan, while in Ontario plants are located in Sarnia and Corunna. While there is also a petrochemical facility in Varennes, Quebec, the Petromont facility, this facility is currently not operating.
The Canadian industry has a total capacity to produce over 5.5 million tonnes or over 12.2 billion pounds of ethylene per year. To put this into perspective, the US petrochemical industry has the capacity to produce close to 28 million tonnes or close to 62 billion pounds per year62. Figure 1.52 illustrates the Canadian petrochemical industry’s ethylene cracking capacity by location as well as by feedstock.
Alberta is the leader for producing petrochemicals, producing a combined annual capacity of ethylene production of approximately 8.6 billion pounds.63 With exports of C$7.1 billion and employing over 7,700 direct jobs, petrochemical production is one of the largest manufacturing industries in the province. The effects are even greater when factoring fertilizers, inorganic chemicals, and specialty and fine chemicals. The top 5 exports are polyethylene (and other ethylene polymers), ethylene glycol, urea, anhydrous ammonia, and styrene64.
The NGLs extracted from the natural gas stream provide the feedstock to the petrochemical industry in Alberta, and without a doubt ethane plays a critical role in the industry, which is primarily ethane-based.
61 National Energy Board, Short-term Outlook for Natural Gas and Natural Gas Liquids to 2006 62 Oil & Gas Journal data. 63 Government of Alberta, Alberta’s Energy Industry: An Overview, June, 2010, pp. 3 64 Government of Alberta, Petrochemicals
July 2012
64 Canadian Energy Research Institute
Figure 1.50: Value-added Chain, Product Prices, and NGLs/ Petrochemical Economics
Source: Chemistry Industry Association of Canada (CIAC), Williams Analyst Day Presentation, RBN Energy65
65 Prices are June 2012 prices.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 65
Figure 1.51: Ethane and Propane and Their Derivative Applications66
Source: NEB, Tudor, Pickering, Holt, & Co.
66 Note that the percentages provided in Figure1.49’s bottom portion correspond to the US and not Canada.
July 2012
66 Canadian Energy Research Institute
Figure 1.52: Canadian Ethylene Cracking Capacity by Location (Tonnes/ Year) and Required Feedstock (%)
Source: Oil & Gas Journal Data, CERI Analysis
Alberta’s petrochemical industry is the result of approximately C$10 billion in capital investment since the 1970s.67 This has spurred the increased production capacity for ethylene, polyethylene, ethylene glycol and linear alpha olefins. Policies such as the Incremental Ethane Extraction Program, introduced by the Government of Alberta in July 2007, encourage greater production of ethane.68 The IEEP was amended in March 2011 for 5 years.
Today there are four major petrochemical plants that utilize ethane feedstock to produce ethylene and propylene. These are owned by Dow Chemicals (Fort Saskatchewan) and NOVA Chemicals (Joffre).
Shell Chemicals owns a facility at Scotford which uses ethylene to produce ethylene glycol and styrene, while Williams’ facilities at Redwater have the capacity to produce polymer grade propylene from the oil sands off-gases. Williams has recently announced the construction of a propane dehydrogenation (PDH) facility to convert incremental volumes of propane to propylene at Redwater. The Alberta Envirofuels plant owned by Keyera produces iso-octane for gasoline blending69.
While these facilities are important users of NGLs in Alberta the focus of the remainder of this section will be on the ethylene crackers. Three of the main ethylene cracking facilities are located in Joffre including the Ethylene 1 (E1), E2, and E3 facilities. Figure 1.53 illustrates the location of the 3 ethylene plants and 2 polyethylene (PE) facilities.
67 NOVA Chemicals. 68 Ibid. 69 Source: Alberta Chemical Operations, Industry Development Branch, Alberta Finance and Enterprise
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 67
NOVA has recently announced that it will expand capacity at its PE2 facility by building a third reactor70. This has the potential to increase the amount of ethylene used by the facility and eventually the amount of ethane needed. These developments are connected to NOVA’s newly acquired incremental ethane supplies of ethane from projects such as Williams’s off-gases as well as the Vantage Pipeline.
E1 and E2 are operated solely by NOVA Chemicals, while E3 is a partnership between NOVA Chemicals and Dow Chemicals. Ethylene and polyethylene are shipped by pipeline to MEG Global/Dow Chemical’s Prentiss Site in the Edmonton area.71 Polyethylene 1 (PE1) and PE2 use ethylene manufactured on site to produce low density polyethylene.
The ethane delivery system (EDS) is operated by Altagas and it moves ethylene (90 mb/d capacity) from NOVA’s site to its customers and storage facilities in Alberta72. The EDS is currently being expanded (Redwater Ethylene Delivery System, REDS) in order to connect increasing feedstock volumes to new storage facilities.73
The Joffre Feedstock Pipeline (JFP) (50 mb/d capacity) runs from Fort Saskatchewan to Joffre. This pipeline is also operated by Altagas and allows NOVA to move various NGLs such as propane, if needed, for cracking in case ethane is not available.74
Figure 1.53: Manufacturing Facilities at Joffre
Source: NOVA Chemicals
70 NOVA Chemicals News Release, NOVA Chemicals website. 71 Ibid. 72 Altagas Annual Information Form 2011 73 NOVA Chemicals News Release, NOVA Chemicals website. 74 Altagas Annual Information Form 2011
July 2012
68 Canadian Energy Research Institute
Dow Chemical’s petrochemical plant is located in Fort Saskatchewan. Using ethane feedstock from a de-ethanizer in Fort Saskatchewan, it also purchases ethane from straddle plants in Empress and Cochrane. The site produces ethylene, polyethylene, and ethylene dichloride.75
CERI estimates the total demand for ethane for the four ethylene crackers in Alberta to be close to 257 mb/d including 81 mb/d for Dow’s Fort Saskatchewan operations and close to 180 mb/d for the Joffre complex.
Sarnia in Ontario has a large and integrated petrochemical complex that is complimented by petroleum refineries, pipeline infrastructure, underground salt caverns and access to large consumer bases in Canada and the US. The area is often dubbed Chemical Valley.
The major petrochemical plants that utilize NGL feedstock in Sarnia-Lambton area include NOVA Chemicals, Imperial Oil and Shell Canada.76
NOVA Chemicals operates three manufacturing facilities in Lambton County. Its Corunna Olefins operation produces and sells ethylene and co-products to nearby companies. The facility operates an ethylene flexi-cracker and is able to produce over 6.5 billion pounds of basic petrochemicals and 3 billion pounds of refinery products annually.77The flexi-crackers are unique in that the crackers process can handle a range of feedstock, both heavy and light hydrocarbons. The facility provides between 30 and 40 percent of total requirements for petrochemicals in the area and can process crude oil, condensate, and NGLs.78
The Corunna facility produces ethylene, propylene, butadiene, iso-butylene, n-butylene, benzene, toluene and xylene; all are feedstocks in other petrochemical activities in the Sarnia- Lambton area.79 NOVA has recently signed agreements with producers and pipeline companies in the Marcellus area as well as made investment commitments for its Corunna facility to be able to take a feedstock 100 percent based on ethane. CERI estimates that NOVA’s facility would require about 50 mb/d of ethane feedstock to be at capacity.
NOVA operates a second facility at Mooretown, Ontario. The St. Clair Township site converts ethylene into polyethylene and has been operating since 1977. NOVA acquired the facility from Union Carbide in 1987. The ethylene feedstock is from its Corunna facility, via pipeline. The facility produces approximately 830 million pounds of polyethylene per year80. Production will increase as the Moore site is being modernized and expanded.81
75 Dow Chemicals 76 City of Sarnia website, Economic Development 77 Sarnia-Lambton, Ontario: Petrochemical and Refining Complex, Sarnia-Lambton Economic Partnership 78 NOVA Chemicals, Corunna Site 79 Ibid. 80 NOVA Chemicals, Moore Site 81 Sarnia-Lambton, Ontario: Petrochemical and Refining Complex, Sarnia-Lambton Economic Partnership
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 69
NOVA’s third facility is located in Corunna and called the St. Clair River site. The plant produces polyethylene and has a capacity of 395 million pounds per year.82 As opposed to the flexi- cracker, the St. Clair River site utilizes SCLAIRTECH™ technology to produce a broad range of products, primarily high-density polyethylene.83 The plant began operations in 1959 and was acquired from DuPont in 1993.84 Like the Moore facility, liquid ethylene is pipelined in from NOVA’s Corunna site.
Imperial Oil operates both oil refinery and petrochemical plants. The former was originally built in 1898 and has a capacity of 121,000 bpd while the latter produces more than 1 million tonnes of petrochemical products, such as polyethylene, solvents, higher olefins and aromatics.85 Feedstocks include ethylene, ethane, propane and propylene, as well as petroleum fractions and naphtha. Imperial Oil has also recently made announcements related to obtaining ethane as a feedstock, sourced from the Marcellus.
NOVA’s and Imperial Oil’s announcement indicate that less NGLs from the WCSB will be required for their operations.
This concludes the discussion of NGLs infrastructure in Canada as well as the overview of NGLs and the Canadian industry.
The following chapter will explain the methodology for developing CERI’s outlook for NGLs in Canada to 2035 and will provide the results with a brief discussion and analysis. Chapter 3 will serve the same purpose but with regards to the United States.
82 Ibid. 83 NOVA Chemicals, St. Clair River Site 84 Ibid. 85 Imperial Oil website, Operations and Refineries
July 2012
70 Canadian Energy Research Institute
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 71
Chapter 2: Natural Gas Liquids Supply and Demand in Canada
Canadian NGL Supply and Demand Forecast: Methodology The methodology for developing an outlook for natural gas liquids in Canada has various components and it is in fact complex and data intensive. The main sources of NGLs in Canada which were considered and modeled include the natural gas production and processing industry, the potential for SGLs from oil sands, as well as the refinery sector.
North American Changing NGLs Infrastructure and Market Dynamics NGL markets in North America are complex and dynamic. A lot of changes have taken place over the last few years and trying to make sense of it all is one of the main purposes of this study.
As it can be observed in Figure 2.1, a lot of infrastructure in North America is being planned around NGL markets. Consequently market dynamics are bound to change and it is important to keep the implications of such changes in mind. While it is not practical to try to include every new development and small detail that could possibly affect the NGL industry in North America in our study, CERI strived to capture most of these changes in our modeling, and, where not possible, acknowledge how these new developments are bound to change existing market dynamics.
Figure 2.1: Changing Dynamics in NGL Markets in North America – Proposed NGLs Pipeline Expansions
Source: Encana Investors Day Presentation, Market Fundamentals
July 2012
72 Canadian Energy Research Institute
Figure 2.2: Alberta NGLs Market Dynamics
Source: ERCB1
NGL markets in Western Canada are complex as illustrated by Figure 2.2, and thus a strong understanding of the supply sources, processing infrastructure, commodities produced, and the different available marketing options for producers in the WCSB is necessary.
1 ERCB ST98-2012: Alberta’s Energy Reserves 2011 and Supply/ Demand Outlook 2012-202
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 73
CERI strived to incorporate all such elements in its modeling in order to obtain accurate and credible supply and demand balances. While it is not practical to explain how each one of these items are considered in the modeling process, this section attempts to cover the most important aspects that were considered in our analysis and the approach used to get our main results, which are then presented in the following section of this chapter.
Natural Gas The most complex supply source relates to the natural gas side of the analysis. This is the case as many factors need to be considered including the available reserves of natural gas liquids and the composition of the natural gas being produced in an area, the supply forecast for a given area, the availability of processing, reprocessing, fractionation, and pipeline infrastructure in an area, as well as the efficiency and capabilities of such infrastructure and the evolving market dynamics. These will be discussed below.
Natural Gas Reserves and Composition CERI has developed a total of 45 different study areas across the WCSB in order to analyze oil and natural gas developments in the region. Figure 2.3 displays a map of those areas for the province of Alberta (23 in total).
CERI made use of the natural gas reserve and composition files as provided by the Alberta Energy Resources Conservation Board (ERCB), as well as the British Columbia Oil & Gas Commission (BCOGC). Using CERI’s mapping and coordinates capabilities based both on the Alberta Township System (ATS) and the Dominion Land Survey (DLS) system, CERI can isolate the natural gas and natural gas liquids reserves and their components to each specific study area. This was done for the production forecast as well as the processing and infrastructure analysis discussed below.
In regards to the reserves, the composition of each area is weighted average based on the remaining producible (RP) volumes of natural gas, or, the remaining marketable gas (RMG) plus the surface losses.
Figure 2.4 illustrates the distribution of the remaining producible volumes of natural gas (bcf), the remaining natural gas liquids reserves (MMb) as well as the average liquids content expressed as a barrel of NGLs per million cubic foot of natural gas (bbl/MMcf) for the study areas in Alberta. The bottom table of Figure 2.4 serves to illustrate the molecular composition of the analyzed reserves by component, by area.
As it can be noticed, areas 6, 9, 10, 13, 14 and 15, with some of the largest producible volumes of natural gas remaining are also some of the areas with the highest volumes of liquids reserves. It is important to keep these characteristics of each area in mind because as drilling and production shifts from (as an example) area 1, which is very low in liquids, to area 10 (liquids-rich), the amount of liquids in the overall gas stream is likely to increase. That is of course, relative to the volumes produced, but if the opposite situation was the case then the stream of gas will become leaner.
July 2012
74 Canadian Energy Research Institute
Figure 2.3: CERI’s Alberta Study Areas & Ethane Reserves
Source: CERI
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 75
Figure 2.4: Alberta Natural Gas Remaining Producible Volumes (bcf), Remaining Natural Gas Liquids Reserves (MMb), and Average Natural Gas Liquids Composition (bbl/MMcf), and Natural Gas Molecular Composition (%) by Component, by CERI Study Area (YE2010)
Source: ERCB Data file, CERI Analysis
July 2012
76 Canadian Energy Research Institute
The same analysis was performed for British Columbia in the same level of detail. Meanwhile, CERI’s own assumptions were used for Saskatchewan’s gas reserves portion of the analysis.
Natural Gas Forecast CERI has developed a natural gas forecast model for Canada. For the WCSB the forecast is provided by study area as discussed above. CERI breaks down the WCSB into 43 sub regions or study areas (referred to as PIA areas) and generates a series of gas forecasts defined by resource type (CBM, shale gas, conventional gas) and by well type (vertical, horizontal).
Figure 2.5 presents the natural gas forecast for Alberta by area. A brief discussion of CERI’s model is provided below.
Figure 2.5: CERI’s Alberta Natural Gas Forecast by Study Area, 2004-2035
Source: ERCB data for historical years, CERI Analysis
Basic information is collected from the Alberta Energy Resources Conservation Board, Saskatchewan Energy and Mines (SEAM) and the British Columbia Oil and Gas Commission (BCOGC) that details the historic production of hydrocarbon fluids. In addition, the three provincial regulators provide data pertaining to each individual well configuration regarding its completion date, initial production date, major production fluid (oil, gas, coalbed methane, bitumen, etc.), original status, current status, total depth, true vertical depth and location (township, meridian, range, section, and legal subdivision).
BCOGC provides the initial production rate (peak month of production in the first 6 months of production), annual production by year, first production date, and last production date (if abandoned).
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 77
Monthly production of gas is summed and averaged on a calendar year basis to establish an average daily production rate (mcf/day) for each year. Individual well production details are assigned to a specific study area based on the Dominion Land Survey System (DLS) location or a National Topographic System location2. The average annual daily rate (mcf/day), for all wells within a given study area that commenced production in a given year, is established and assigned to each year starting from the initial production year and including each consecutive year.
This process is repeated for each analysis year from 2000 through 2011 in order to establish a family of vintage production curves for each study area. A series of harmonic and exponential curves are investigated to establish a representative “Type” decline curve for a given study area. This process is replicated for vertical and horizontal wells separately.
The “Type” curve is used to establish the decline path for wells that are currently on stream (as of the base year 2011), based on the average number of years the existing operating wells have been operating. The average on stream years defines the starting point on the “Type” curve where the production rate will be for the forecast years. This same curve starting at time zero is used to define the production path for new wells drilled and connected in the future. The initial production rates for the years 2000 through 2011 are shown on the same chart and used to extrapolate the future declines or inclines in initial production rate for wells drilled in the future. Simple regression curves are established to forecast the change in the initial production rate (per well) in the future for a given study area and well type.
CERI has further developed a US gas supply and demand model, jointly developed with What- If? Technologies, to determine the amount of gas that will be needed to offset any US supply deficiency, on a year by year basis. This level of US imports is added to the domestic Canadian gas and is used to develop a drilling forecast for the WCSB.
The US supply model incorporates the most recent EIA production forecasts and layers on top production increases or decreases as a result of changing drilling activity on a state by state basis to bring the model in line with current activity. The US demand model is a detailed bottom up model that generates demand forecasts for Residential, Commercial, Industrial and Power Generation in addition to estimates of LNG exports, exports to Mexico, pipeline fuel and losses and other uses. The combined workings of these models results in a North American Supply/Demand forecast.
The important trend observed here (Figure 2.5) is that as we move forward in time, CERI’s natural gas production model indicates that as a percentage of the total produced volumes, certain areas decline while others gain shares.
2 A National Topographic System (NTS) location is available for wells drilled in British Columbia outside of the Peace River block.
July 2012
78 Canadian Energy Research Institute
As an example, most of the areas that contribute to the overall increase in production growth going forward are areas such as 6, 10, 13, 14, and 15, which are in turn areas that have high levels of liquids content across the province. This is an important implication for the amount of natural gas liquids available in the produced natural gas stream.
Putting together the natural gas production forecast and the composition of the natural gas allows us to understand what the amount of liquids available in the stream is. An example for this in regards to the ethane is provided below in the NGLs outlook section.
Natural Gas Processing Infrastructure CERI analyzed data for all of Alberta and British Columbia’s natural gas processing facilities for the past decade including their capacities, their outputs, and their liquids yields. This analysis was then aggregated on an area by area basis and was further broken down to separate components such as specification products from natural gas field plants versus NGL mixes, as well as to separate field plants from straddle plants (or reprocessing plants) and NGL fractionators.
As an example, Figure 2.6 illustrates the analysis conducted by CERI in regards to Alberta’s field plants. A total of 1,084 facilities were analyzed including field plants, fractionators, and straddle plants.3 CERI is aware that this is in fact not the actual number of active plants in the province at the moment, but it is the number of plants that was selected as having some sort of activity within the period analyzed (2002-2012). The ERCB estimates that in 2011 a total of 520 plants in the province conducted some type of liquids recovery, together with 8 fractionators and 9 straddle plants.4
It is important to clarify that the capacity of the plants (both for gas processing and liquids extraction) was calculated by CERI as the stated capacity or the maximum processed capacity at one point in time during the surveyed period.
Figure 2.6 indicates that there is a large amount of underutilized gas processing and liquids extraction capacity at the field level. Also, while the liquids yield declined at the start of the period and remained stable for most of the decade, the last couple of years have seen an upward trend. This once again indicates that either the gas stream is getting richer, or that producers are increasing their extraction efficiencies, or both.
The important piece of information from this analysis was the liquids yield. What the liquids yield allows us to determine is the likely composition of the gas being processed by each plant in each area. Theoretically, if a field plant had an extraction efficiency of 100 percent, the amount of liquids being produced by the plants should be equally reflective of the composition of the gas being produced and processed in the area.
3 The results as presented in Figure 2.6 can be obtained for any single or specific group of plants given by area of production capabilities. 4 ERCB ST98-2012: Alberta’s Energy Reserves 2011 and Supply/ Demand Outlook 2012-2021
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 79
While we are aware that not all the gas being produced in one area is necessarily processed in the same area, trying to identify such flows is almost impossible given the amount of gathering pipelines in the province. Thus in some areas, individual calibration was required.
Figure 2.6: Alberta Field Plants Gas Processing Capacity Throughput (MMcf/d), Liquids Production Capacity and Output (mb/d), Utilization Rates (%) and Liquids Yields (bbl/ MMcf), 2002-Q12012
Source: ERCB data,5 CERI Analysis
5 ERCB ST13B: Alberta Gas Plant/Gas Gathering System Activities.
July 2012
80 Canadian Energy Research Institute
Thus, the liquids yield as a function of the composition of the gas in the area represents the extraction efficiency of the liquids at the field level. As an example, if the composition of the natural gas indicates that the molecular percentage of ethane in that area is 4.2 percent and the analysis of the field extracted ethane in the area indicates that the extracted gas was 1.8 percent ethane, then the extraction efficiency of ethane in that area was 43 percent (1.8/4.2 = 0.43). The remaining 58 percent is either extracted as an NGL mix (where possible), by the straddle plants (depending on the flow), or either left in the stream of the marketable natural gas. This approach reliably replicates historical production rates of field spec liquids as seen in Figure 2.7.
Figure 2.7: Modeled Spec Ethane Field Extraction versus Actual, 2002-Q12012
Source: ERCB data,6 CERI analysis
With NGL mixes produced at the field level the story is somewhat different because it is difficult to determine what the composition of that NGL mix is. However, there are ways to estimate their composition with reasonable accuracy.
One way is by looking at the product being produced by the fractionators. The output coming out of the fractionators is directly related to the product coming into the fractionator because the fractionator function is to break down the liquids into its individual components, and therefore, theoretically, no volume losses or gains occur in the process.
It can be determined that fractionators in the Fort Saskatchewan area (major fractionation center) receive the majority of their product via pipeline and some propane plus NGLs volumes (from the closest areas) via trucks or rail. Knowing which pipeline systems are connected to the fractionators (Pembina pipelines NGLs system primarily but also Co-Ed system) and knowing which fields and plants are connected to those pipelines allow us to understand the makeup of the NGL mixes being produced in those plants. This is shown in Figure 2.8.
6 Ibid.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 81
The composition of the NGL mix for each area connected to each pipeline system is then determined and, similar to the estimation of the extraction efficiency for the spec product, the extraction efficiency for each liquid in the NGL mix is modeled. This in turn will determine the amount and the type of liquids available to the fractionators going forward.
Figure 2.8: Fort Saskatchewan Fractionators Total Liquids Production and Feed Sources, 2002-Q12012 (mb/d)
Source: ERCB, BCMEMPR, and Pembina Pipelines data, CERI Analysis
July 2012
82 Canadian Energy Research Institute
This approach works well to determine the amount of a given liquid in the NGL mix stream as shown in Figure 2.9.
One of the last pieces of the analysis involves the straddle plants. The straddle plants act as re- processors and thus extract the liquids remaining in the gas stream after the liquids have been partially recovered at the field level either in form of spec product or a NGL mix.
Figure 2.9: Modeled Ethane in NGL Mix Extraction versus Actual, 2002-Q12012
Source: ERCB data,7 CERI analysis
Going back to the example of the efficiencies above, if the gas from Area 3 was 4.2 percent ethane and 1.8 percent ethane is extracted in the form of spec ethane at the field level, and 1.3 percent ethane is extracted in the form of an NGL mix at the field level, the remaining 1.1 percent (or 26 percent of the total) is what will enter the main pipeline system.
Once in the pipeline system, this gas will either be consumed locally, i.e., intra-Alberta demand, where this gas could potentially be re-processed at one of the smaller intra-Alberta straddle plants, or, it is possible that it would be destined to export markets, where substantially all of the gas passing through the border is processed at the large straddle plants. Within CERI’s natural gas supply model, a pipeline flow and demand model was constructed for the NGTL system which allows us to track the flows of gas to different straddle points with a high degree of accuracy.
As an example, Figure 2.10 illustrates the CERI modeled volumes of natural gas throughput (inlet) for the Cochrane straddle plant versus the actual volumes as reported by ERCB data.
Finally, knowing the composition of the gas flowing through the NGTL system (liquids in gas stream minus liquids extracted as spec products and NGL mixes at the field level) then we know in theory the volume of barrels of each liquid that is flowing in the gas stream through the pipeline system.
7 Ibid.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 83
Using historical data from the ERCB and comparing the barrels flowing through the straddle plant versus the number of barrels extracted we can calculate the extraction efficiency of each straddle plant, which is used for the forecast years. This allows CERI to estimate the liquids of volumes being produced at the straddle plants over the forecast period.
Figure 2.10: Modeled Inlet Natural Gas Flows at Cochrane Straddle Plants versus Actual, 2002-Q120128
Source: ERCB data,9 CERI analysis
Finally, new and upcoming developments that affect the natural gas processing side of the supply picture were incorporated into the model. These include the proposed imports of ethane through the North Dakota to Alberta Vantage pipeline, as well as projects under the government’s incremental ethane extraction policy (IEEP).
Oil Sands Plants/Upgrader Off-Gases Determining the potential for SGLs production from off-gases has several components.
First, CERI surveyed various publicly available documents in order to understand the possible composition of upgrader off-gases including environmental impact assessment (EIAs) applications from proposed upgraders as well as presentations from both Williams and Aux Sable, who are the operators of the existing off-gas processing plants in the province. Conversation with analysts from the ERCB as well as personnel from Williams served to confirm the estimates developed by CERI. These estimates are presented in Table 2.1 below.
8 Note that while it can be debated that the volumes passing through (inlet) Cochrane are simply a function of the volumes being exported to the US through the GTN system, CERI’s model actually flows gas volumes from the field level, down the NGTL system and aggregates it at the border points for exports. This in fact proves that the modeled flows are accurate. 9 ERCB ST13B: Alberta Gas Plant/ Gas Gathering System Activities.
July 2012
84 Canadian Energy Research Institute
Table 2.1: Upgrader Off-Gas Analysis
ATHABASCA AREA MOL % Mol # Gal/ # of Mol Gal/ mcf bbl/ MMcf Williams Presentations NGLs/ Olefins Mix 235 Offgas Composition HYDROGEN H2 20 METHANE CH4 40 Synthetic Gas Liquids (SGLs) NGLs/ Olefins 40 1.05 13.64 325 Ethane C2 Based on off-gas production of 318 MMcf/d and estimated 37 kb/d in stream 116 Propane Plus Mix C3+ Based on off-gas production of 318 MMcf/d and estimated 43 kb/d in stream 135 Total NGLs/ Olefins Based on off-gas production of 318 MMcf/d and estimated 80 kb/d in stream 252 ERCB ST-98 ETHANE 17 0.45 10.13 5 108 Athabasca Area Summary (MEDIAN) ETHANE/ ETHYLENE MIX C2/ C2= 112 PROPANE PLUS MIX C3+ 139 Synthetic Gas Liquids (SGLs) NGLs/ Olefins 252
INDUSTRIAL HEARTLAND AREA MOL % Mol # Gal/ # of Mol Gal/ mcf bbl/ MMcf TOTAL - Delayed Coker Application HYDROGEN H2 41 1.08 METHANE CH4 35 0.93 - - ETHYLENE C2H4 - - 10.13 - - ETHANE C2H6 21 0.54 10.13 6 131 PROPYLENE C3H6 - - 10.43 - - PROPANE C3H8 - - 10.43 - - BUTYLENE C4H8 - - 12.39 - - BUTANE C4H10 - - 12.39 - - Total 97 2.56 65.89 6 131 Total Liquids 21 0.54 65.89 6 131 STATOIL - Delayed Coker Application HYDROGEN H2 12 0.31 METHANE CH4 37 0.96 ETHYLENE C2H4 3 0.07 10.13 1 17 ETHANE C2H6 20 0.53 10.13 5 128 PROPYLENE C3H6 4 0.11 10.43 1 26 PROPANE C3H8 12 0.32 10.43 3 79 BUTYLENE C4H8 4 0.10 12.39 1 30 BUTANE C4H10 9 0.24 12.39 3 71 Total 100 2.64 65.89 15 351 Total Liquids 52 1.36 65.89 15 351 Aux Sable Presentations ETHANE PLUS MIX C2+ Based on off-gas production of 260 MMcf/d and estimated 65 kb/d in stream 250 PHASE 1 UPGRADER OFF GAS ETHYLENE C2H4 Based on off-gas processing of 15 MMcf/d and estimated 2.2 kb/d in stream (40% C2H4) 59 ETHANE C2H6 Based on off-gas processing of 15 MMcf/d and estimated 2.2 kb/d in stream (60% C2H6) 88 PROPANE PLUS MIX C3+ Based on off-gas processing of 15 MMcf/d and estimated 2 kb/d in stream 133 Synthetic Gas Liquids (SGLs) 280 ERCB ST-98 ETHANE 17 0.45 10.13 5 108 Industrial Heartland Area Summary (MEDIAN) ETHANE/ ETHYLENE MIX C2/ C2= 138 PROPANE PLUS MIX C3+ 127 Synthetic Gas Liquids (SGLs) NGLs/ Olefins 265
ALBERTA SUMMARY (Median) ETHANE/ ETHYLENE MIX C2/ C2= 125 PROPANE PLUS MIX C3+ 133 Synthetic Gas Liquids (SGLs) NGLs/ Olefins 258 Sources: Various data sources,10 CERI Analysis
10 Williams Analyst Day Presentation: http://www.b2i.us/Profiles/Investor/Investor.asp?BzID=630&from=dl&ID=136006&myID=136006&L=i&Validate=3 &I= Aux Sable Presentation at Canadian Institute NGL Conference: http://www.auxsable.com/news/ppt/2008- NGLConfApril-10-2008-FINALv1.pdf Williams Presentation to the EEDC: http://www.edmonton.com/files/David_Chappell.pdf Total Upgrader Application – Supplemental Information Form: ftp://ftp.gov.ab.ca/env/fs/eia/2007-12- TotalEandPCanadaLtdUpgrader/Working%20PDF/Supplemental_Information/SIR.pdf North American Oil Sands Upgrader Project Application: ftp://ftp.gov.ab.ca/env/fs/eia/2007-12- StatoilHydroCanadaLtd(formNorthAmericanOilSandsCorp)Upgrader/Documents/Files/Volume%201.pdf ERCB ST-98: Alberta’s Energy Reserves 2011 and Supply/ Demand Outlook 2012-2021.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 85
Analysis of the ERCB ST-39 data for Upgraders served to determine a ratio of off-gas produced, by upgrading technology, per barrel of bitumen processed or per barrel of SCO produced. CERI’s Oil Sands Database and Forecasting model was used to generate an off-gas production outlook. However, it is important to consider that this outlook will be strictly related to the outlook for SCO production. CERI’s outlook for SCO production is presented in Figure 2.11 and it is compared with other recent forecast from the NEB and the ERCB.
Figure 2.11: Synthetic Crude Oil Production (mb/d), Analysis, Forecast, and Comparison, 2007-2035
Source: ERCB, NEB,11 CERI Analysis
The main differences in the forecasts are due to CERI’s assumptions on upgrading infrastructure which have probability factors and capacity constraints attached to each project given their status. Further, CERI assumes that as legacy mining projects reach the end of their operating life so does the accompanying upgrading infrastructure for integrated projects.12
The next section of the analysis was then to develop a forecast for upgrader off-gases production. This was done on a project by project basis where the projects were divided in two main areas: Athabasca and Industrial Heartland.
11 ERCB ST98-2012: Alberta’s Energy Reserves 2011 and Supply/ Demand Outlook 2012-2021; NEB: Canada’s Energy Future: Energy Supply and Demand Projections to 2035 – Energy Market Assessment. 12 While it can be debated whether or not that will be the case, this is done to keep the analysis manageable as CERI’s oil sands model works on a project phase by project phase basis for which there are over 300 project phases being analyzed and thus adjusting for all the small details will be counterproductive.
July 2012
86 Canadian Energy Research Institute
This is presented in Figure 2.12 where the top chart indicates the total off-gas production in the province, while the middle and bottom charts display the production from each of the Athabasca and Industrial Heartland areas by project.
Combining the off-gas composition analysis with the off-gas production outlook allows CERI to come up with an estimate of the potential of available SGLs in the off-gas stream. The results of this analysis are presented in the next section of the report which presents the outlook results.
Refineries Refineries are an important source of supply of propane and butanes (LPGs) in Canada. While the volumes produced by refineries in the overall context of natural gas liquids in Canada only account for between 10 to 15 percent, it is still important to keep these sources in mind.
CERI’s crude oil and oil sands supply models indicate that flows of Canadian crude will continue to reach conventional US mid-continent and eastern markets and eventually expand to the Asia-Pacific markets and the US Gulf Coast. Meanwhile, while the idea of moving oil sands crude to Eastern Canadian refineries has been discussed, no concrete steps have been taken to make that happen. With that in mind, the assumption then is that crude flows to Canadian refineries will continue to be similar to what they have been historically. Further, with no major known refinery upgrades or construction in Canada, it is reasonable to assume the output of LPGs to be consistent with historical trends.
This could however change and that is worth noting. As an example, if heavier crudes from Western Canada make their way to Eastern Canadian refineries the end result could be lower output of LPGs as these crudes have lower percentages of lighter ends. Further, Imperial Oil recently announced that it has put its Dartmouth (Nova Scotia) refinery up for sale, which could eventually result in closure if a sale does not occur. Other things being equal this would somewhat reduce the amount of LPGs produced in Canada overall, although not significantly.
On the upside, there is potential for new upgrading/refining projects such as the Northwest Upgrader to increase (although not significantly) the amount of refinery LPGs in Canada.
With all these considerations, LPGs output for refineries was held constant over the outlook period.
Demand Side and Other Considerations Demand for ethane is primarily a function of Alberta’s petrochemical industry capacity to absorb available local supplies. However, ethane demand in Ontario’s petrochemical industry will increase over the next couple of years.
CERI estimates that the NOVA Chemicals and Imperial Oil plants combined are able to absorb a total of 72 mb/d of ethane as these plants are re-tooled to be completely fed by an ethane feedstock.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 87
Figure 2.12: Upgrader Off-Gas Production Analysis, Forecast, and Comparison, 2007-2035
Source: ERCB historical data,13 CERI Analysis
13 ERCB ST98-2012: Alberta’s Energy Reserves 2011 and Supply/ Demand Outlook 2012-2021; ERCB: ST-39 Alberta Mineable Oil Sands Plant Statistics.
July 2012
88 Canadian Energy Research Institute
Ethane supply for these plants in excess of local supply is expected to come via pipeline from the Marcellus area in the northeastern United States and does not affect the ethane story in western Canada. This is also the case as currently no ethane can be transported from the WCSB to southern Ontario. Further, Kinder Morgan’s proposal to reverse the Cochin pipeline will eliminate any NGLs spec product outlet from the WCSB. While this pipeline does not transport ethane at the moment, none of the other currently existing pipelines ship NGLs in spec form out of the WCSB to the Ontario, US Midwest, and Northeast areas.
Demand for propane and butanes in Alberta for the outlook period was adapted from the latest ERCB ST-98 report which provides estimates for the 2012 to 2021 time period. CERI extrapolated these estimates to the end of the outlook period (2035. These figures consider the increased use of butanes as a diluent for crude bitumen transportation.
Demand for propane and butanes across the rest of Canada were also considered. Demand for propane comes from various sources across Canada including the industrial, commercial, and residential sectors. Propane use in these sectors is for the purpose of heating but it is also used as a motive fuel. Demand is a function of increased activity in these sectors which are in turn related to the level of economic activity and population growth. CERI assumed a 1.5 percent propane demand growth rate from 2011 until the end of the forecast period.
In Canada, outside of Alberta, butanes are used primarily in refineries, which as stated above, are assumed to maintain production levels at historical levels. Other uses for butanes include the use as a petrochemical feedstock in Ontario which is expected to be displaced by ethane. Finally butanes are also used for heating, which, as with the case for propane, is related to increased levels of economic activity and population trends. Since there are both upside and downside pushes in the demand trend for butanes outside of Alberta, demand was held constant at 2011 levels.
The Alberta and rest of Canada demand figures were added in order to come up with demand estimates for both propane and butanes, these figures are presented in the results section below.
Demand for pentanes plus is driven by CERI’s oil sands supply model which uses a blending model to estimate required diluent volumes for oil sands operations.
Due Diligence CERI strives to be a leader in the analysis of the energy industry. In our view, good analysis requires good data, sound methods, as well as accurate and substantiated results. CERI only made use of data available in the public domain to conduct this analysis.
Further, as shown in various examples above, an effort was made with any step along the modeling process to make sure that a model which is used to forecast future results can prove that it is also able to replicate or come up within a reasonable estimated range of historical data. This makes our models not only more accurate but also more credible.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 89
Finally, when presenting our results for Canada we compare them with recently released similar analysis from other organizations. This further strengthens our credibility. While our results are not expected to be the same as others’ we strive to understand and explain why those results are different and the reasons behind them.
As with any forecasting exercise, there are both upside and downside risks and we have tried to make readers aware of those throughout both our analysis and our results sections. The following section presents CERI’s results for NGLs supply and demand in Alberta and Canada.
Alberta NGLs Outlook and Analysis Natural Gas Forecast The starting point for the outlook entails the natural gas production outlook. Figure 2.13 presents the outlook for natural gas production in Alberta, British Columbia, and Saskatchewan produced by CERI as well as a comparison with similar analysis carried out by the National Energy Board (Canada’s Energy Future 2011), the Alberta Energy Resources Conservation Board (ERCB ST98-2012), and the latest WCSB forecast provided by TransCanada Pipelines (TCPL) in its mainline tolls application.
Figure 2.13: CERI’s Marketable Natural Gas Analysis, Forecast, and Comparison, 2004-2035
Source: ERCB, NEB,14 CERI Analysis
As it can be observed, while CERI’s natural gas outlook is very much in line with the others, some exceptions are notable.
14 ERCB ST98-2012: Alberta’s Energy Reserves 2011 and Supply/ Demand Outlook 2012-2021; NEB: Canada’s Energy Future: Energy Supply and Demand Projections to 2035 – Energy Market Assessment, TCPL Mainline Tolls Application, NEB.
July 2012
90 Canadian Energy Research Institute
In regards to Alberta gas production, CERI and the ERCB have very similar outlooks over the covered period, while the NEB production outlook (long-term) is much lower than CERI’s. British Columbia production from the NEB analysis grows much higher than CERI’s while the outlook for Saskatchewan is very similar. TCPL’s forecast for the WCSB is driven by substantial and rapid increases from production volumes both in the Horn River and Montney areas. Figure 2.13 also shows that CERI’s model is capable of replicating historical/actual numbers with a high degree of accuracy thus indicating sound analysis and sound modeling for the outlook years.
Ethane In regards to ethane, an important consideration is the analysis of the natural gas reserves which in turn, taken together with the natural gas outlook, determines the amount of ethane available in the natural gas stream. This is shown in Figure 2.14.
As it can be observed, CERI’s analysis for Alberta is consistent with the NEB for the initial years, while it differs in the long term, driven by the shape of the natural gas production curve (see Figure 2.13). British Columbia and Saskatchewan volumes of available ethane in the natural gas stream are also consistent in the initial years and differ in the long run due to differences in the shape of the natural gas outlook. The ERCB’s analysis of Alberta’s gas stream indicates a lower percentage of ethane in the stream relative to CERI. CERI’s analysis of potential ethane entrained in oil sands upgraders’ off-gases streams is very much in line with that produced by the ERCB.
Figure 2.14: CERI’s Ethane Entrained in the Natural Gas Stream, Analysis, Forecast, and Comparison, 2004-2035
700
600
500
400
MMCF/D 300
200
100
- 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 HISTORICAL/ ACTUAL OUTLOOK
TOTAL ETHANE AVAILABLE IN SK GAS-CERI TOTAL ETHANE AVAILABLE IN AB,BC,SK GAS-CERI TOTAL ETHANE AVAILABLE IN AB GAS-ERCB(ST982012) TOTAL ETHANE AVAILABLE IN AB GAS-NEB(NRGFUTURES2011) TOTAL ETHANE AVAILABLE IN BC GAS-NEB(NRGFUTURES2011) TOTAL ETHANE AVAILABLE IN SK GAS-NEB(NRGFUTURES2011) TOTAL ETHANE AVAILABLE IN AB,BC,SK GAS-NEB(NRGFUTURES2011) TOTAL ETHANE AVAILABLE IN AB GAS-CERI TOTAL ETHANE AVAILABLE IN BC GAS-CERI POTENTIAL ETHANE IN OIL SANDS OFF-GAS-ERCB(ST982012) Source: ERCB, NEB,15 CERI Analysis
15 ERCB ST98-2012: Alberta’s Energy Reserves 2011 and Supply/ Demand Outlook 2012-2021; NEB: Canada’s Energy Future: Energy Supply and Demand Projections to 2035 – Energy Market Assessment.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 91
Figure 2.15 shows the differences between the outlooks for ethane supply between CERI, the NEB, and the ERCB. The ERCB analysis simply indicates that supply will remain flat to the point where it meets demand, thus implying that only the required amount of ethane to fulfill the need of the currently existing petrochemical facilities will be produced and nothing beyond. The NEB analysis is driven by the volumes of gas production which are lower in the future and continue on a downward trend.
CERI’s analysis incorporates the current supply sources of ethane including spec ethane from field plants in the Western Canadian Sedimentary Basin (WCSB), ethane entrained in produced NGL mixes, ethane produced by Alberta fractionators, and ethane produced by the straddle plants as well as the emerging or diversified ethane sources which include ethane extracted from oil sands upgraders off-gases and refineries fuel gases, ethane imports from North Dakota (and Saskatchewan) as well as projects which are currently being considered by the GOA under the IEEP.
Figure 2.15: CERI’s Ethane Supply Analysis, Forecast, and Comparison, 2004-2035
Source: ERCB, NEB,16 CERI Analysis
Figure 2.16 displays CERI’s outlook for ethane production and supply in the WCSB from various sources, as well as the percentage split by traditional (field, fractionators, and straddles) as well as the emerging sources.
CERI’s analysis indicates the potential for ethane production is well above and beyond current demand. This presents an opportunity for expansion of the petrochemical industry in the province, but it could also mean that ethane will only be produced to the current maximum demand level and the potential above will be not extracted, thus indicating that some suppliers will have to give up share of the market.
16 Ibid.
July 2012
92 Canadian Energy Research Institute
Further, our results indicate that over the short-term (about three to four years) there will continue to be excess demand capacity from Alberta’s petrochemical industry. However, by 2016, given a combination of various factors including an upswing in natural gas production volumes, a richer natural gas stream, increased flow through the border straddle plants, and increasing volumes from oil sands off-gases, IEEP projects, as well as imports, ethane supply can exceed the current demand capacity in Alberta.
Figure 2.16: CERI’s Ethane Supply and Demand Analysis and Outlook, 2004-2035
Source: ERCB, NEB,17 CERI Analysis
17 Ibid.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 93
By the end of the forecast period (2035), there can be enough ethane supply to support the construction of more than one world-scale ethylene cracker in the province.
On the other hand, any potential ethane supply above and beyond existing petrochemical infrastructure capacity can simply be left in the stream and burned for heating value if no additional demand is created. In such a situation, as seen on the bottom part of Figure 2.16, given the increased share of the emerging ethane supply sources, some of the traditional supply sources will most likely lose share in the market.
Propane Figure 2.17 presents CERI’s outlook for propane. This outlook indicates that supply will exceed amounts required by local markets and that there will be increased opportunities for exports.
Figure 2.17: CERI’s Propane Supply and Demand Analysis and Outlook, 2004-2035
Source ERCB, NEB, CERI Analysis
July 2012
94 Canadian Energy Research Institute
Export amounts have dramatically reduced over the past three years and will slowly recover to historical levels over the near term of the forecast. Traditionally, (spec) propane exports from Alberta will find their way to PADDs II, V, and IV. Locally produced propane supply is growing in PADDs II and IV increasing competition for any further growth in Canadian exports. The combination of growing Canadian exports and local supply growth will cause excess propane volumes to be displaced to PADD III in the Gulf Coast. Those excess volumes will need to be exported internationally to balance the market. Exports to PADD V are traditionally done by rail, exports to PADD IV by rail/truck, and those going to PADD II are most likely to be delivered via the Cochin pipeline. The latter outlet will no longer exist as of 2014, as Kinder Morgan has decided to reverse the flow on the pipeline in order to move condensate (diluent) from the US to Alberta (for oil sands operations). This has implications for propane producers in Alberta and Western Canada as markets previously served by pipeline will now need to be served via rail or truck. Rail and truck will be more costly transportation options to traditional markets, and will tend to widen the basis differential deflating Alberta propane prices.
In the Canadian context, Alberta (spec) propane has been traditionally exported primarily to Ontario (via Cochin/rail), but also to Saskatchewan, British Columbia, and Manitoba. Rail will continue to be an option for short distances, and the existing Spectra Empress pipeline which transports propane and butanes across Alberta, Saskatchewan, and Manitoba will continue to provide an outlet for Alberta propane in Western Canada. Exports to Ontario can be affected in the long-run similarly to those in the US Midwest given the reversal of the Cochin pipeline. Further, increasing volumes produced in the northeastern US could provide a competitively priced alternative supply to Ontario’s market which can then result in lower volumes of propane from Western Canada making their way to Eastern Canada.
Overall, there are concerns in regards to the prices at which increased Western Canadian propane production will find a market. Alternatively, this is an opportunity for Canadian producers to try and export propane directly to the world market possibly via new routes such as ports in British Columbia, Ontario, or Quebec. However, developing new markets means developing new infrastructure which can take a long time and will require significant investments. Thus, the volume displacement alternative (as presented above) is more likely to be the outcome over the coming years.
Further, propane demand in Alberta has the potential to increase over the long run as new oil sands production schemes consider the use of solvents such as LPGs for SAGD operations. Additionally, some service companies have started to market propane and LPGs as an alternative to fluids currently used in fracking operations. Other local demand sources for propane should be considered by producers over the long run as there appear to be challenges in regards to traditional markets and outlets for exports.
Finally, the Enbridge mainline will continue to provide an outlet for propane plus mixes while the Rangeland pipeline system will continue to provide capacity to export some spec product volumes.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 95
Butanes Figure 2.18 presents CERI’s outlook for butanes. This outlook indicates that exports from Alberta will disappear over the next couple of years.
Figure 2.18: CERI’s Butanes Supply and Demand Analysis and Outlook, 2004-2035
Source: CERI Analysis
Increasing demand for butanes driven by its use as a diluent will keep the local market tight for the next few years, and by 2018 it is anticipated that imports of butanes would be required. Alternatively, more NGL mix could make its way to the fractionators in the Edmonton/Fort Saskatchewan area, thus increasing the supplies of spec butanes, or, field plants could increase extraction efficiencies.
In the case that imports become the norm, it is possible for butanes to get a price premium over current prices.
July 2012
96 Canadian Energy Research Institute
Pentanes Plus Figure 2.19’s top portion shows the supply of pentanes in the Alberta area with its different components, while the bottom portion shows the supply and demand balance. CERI estimates that local supply will continue to decline through 2015 to just under 100 mb/d at which point will start a recovery trend reaching 2007 levels over the remainder of the forecast.
Figure 2.19: CERI’s Pentanes Plus Supply and Demand Analysis and Outlook, 2004-2035
Source: ERCB, NEB, CERI Analysis
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 97
As has been the case since 2004, increasing volumes of pentanes will be required as a diluent to move crude bitumen from growing oil sands operations. CERI’s analysis indicates that by the end of the outlook period, as many as 1.2 million barrels per day of pentanes/pentanes plus condensate will be required in Alberta. That is of course assuming that oil sands producers will have continued availability of reasonably priced diluent. This can potentially become an issue for oil sands producers. Alternatively, the rate of growth of oil sands projects may slow down, or given the proper market conditions, more upgraders could be built in the province thus reducing the need for pentanes plus as a diluent.
Natural Gas Liquids and NGL Mix Figure 2.20 displays the overall outlook for NGLs production in Alberta as developed by CERI and compared to similar outlooks developed by the NEB and the ERCB.
Figure 2.20: CERI’s Natural Gas Liquids Supply and Demand Analysis and Outlook and NGLs Mix Composition, 2004-2035
Source: ERCB, NEB, CERI Analysis
July 2012
98 Canadian Energy Research Institute
Total liquids production is estimated by CERI at 564 mb/d for 2012 compared to 542 mb/d by the ERCB. CERI’s outlook for total liquids production reaches a low at 498 mb/d by 2014 then increases steadily to reach 790 mb/d by 2035 as natural gas production volumes recover in the long-term.
Figure 2.20 also displays the net available NGL mix production as estimated by CERI. This mix represents an opportunity for further liquids processing and fractionation in the province, if feasible, and with the proper transportation infrastructure in place, but also represents the export potential that can be sent to fractionators in Ontario or the US.
Potential Supply of Synthetic Gas Liquids (SGLs) CERI’s analysis indicates that by the earlier part of the next decade as many as 170 mb/d of SGLs will be available on the oil sands upgrader off-gases stream (Figure 2.21).
Figure 2.21: Potential Supply of SGLs in Alberta by Components, by Area, and by Level of Recovery, 2007-2035 (mb/d)
Source: CERI Analysis
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 99
This mix is expected to be about a 50/50 split between an ethane/ ethylene mix (C2/C2=) and a propane plus (C3+) SGLs mix which includes propane, propylene, butanes, and butylene, as well as olefinic condensate.
CERI’s analysis also indicates that about 60 percent of these potential SGLs will be entrained in the off-gases produced in the Athabasca area, while the remainder will be produced by upgraders in the Industrial Heartland area. CERI has also provided guidelines to estimate the total level of SGLs produced if 25, 50, 75, or 100 percent of these SGLs were extracted.
Without a doubt, off-gases have the potential to provide large amounts of SGLs in the province leading to the possibility of various value-added industries’ expansion or even creation.
Figure 2.22 provides an estimate of the available ethane in the off-gas stream as developed by CERI and compared to a similar estimate developed by the ERCB. As previously stated, the differences are not given by differing assumptions on the off-gas composition but rather the SCO production outlook which in turn dictates the amount of off-gases produced and thus the available ethane in the stream.
Further, Figure 2.22 illustrates the availability of the ethane by area, and the estimated ethylene and propane plus potential, as well as guidelines that indicate assumed different extraction or recovery levels.
Canadian Outlook for Propane and Butanes Figure 2.23 displays CERI’s supply and demand balance for propane in Canada. Demand is expected to grow steady over the outlook period while propane supply (including propane and propane plus) is expected to fall over the next decade, driven by a drop in the propane entrained in the NGLs mix. After 2020, the propane supply levels stabilize.
Overall, this means less propane available for export as supply decreases and levels of demand continues to increase. However, available export volumes will increase later in the outlook period.
Figure 2.23 further shows that CERI’s supply and demand outlook is consistent with a similar analysis recently performed by the NEB.
Figure 2.24 illustrates CERI’s supply and demand analysis for butanes in Canada. Our results indicate that increasing import volumes will be required over the outlook period to meet Canadian demand.
The demand trend is mainly driven by demand in Alberta. Demand for the rest of Canada is expected to be flat. As in the case for propane, CERI’s results are consistent with those produced by the NEB.
July 2012
100 Canadian Energy Research Institute
Figure 2.22: Estimated Ethane, Ethylene, and Propane Plus SGLs Available in Oil Sands Off-gases by Area, Component, and Level of Recovery, 2007-2035 (mb/d)
Source: ERCB ST98 data for comparison, CERI analysis
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 101
Figure 2.23: Canadian Propane Supply and Demand Balance, 2004-2035 (mb/d)
Source: NEB data for comparison, CERI analysis
Figure 2.24: Canadian Butanes Supply and Demand Balance, 2004-2035 (mb/d)
Source: NEB data for comparison, CERI analysis
July 2012
102 Canadian Energy Research Institute
Summary and Conclusion The outlook and analysis for Alberta and Canada can be summarized as the placing of the liquids into two groups, those that present opportunities and those that present challenges and risks. However, it is important to keep in mind that opportunities require concrete actions to be realized and challenges and risks can be turned into opportunities and certainty.
CERI estimates substantial growth in ethane availability from a diversified portfolio of sources. It is expected that spec ethane will not be exported from the WCSB, so whether or not that increase in available ethane is actually extracted depends on whether or not local petrochemical producers expand their ethane cracking requirements.
Opportunities exist to increase the capacity of the currently existing ethane-based petrochemical industry in Alberta and/or build one or two new world-scale ethylene crackers in the province over the long-term given the estimated available ethane supply. Alternatively, ethane volumes in excess of local demand risks being left in the natural gas stream and sold for its heating value rather than being processed and moved up the value-added chain.
Opportunities also exist to find new markets for propane exports as the US continues to become self-sufficient. Alternatively, new sources of demand should be considered in Canada including potential to develop propane-based petrochemical (propylene) plants. Other opportunities for increased propane and LPGs demand include solvents for oil sands SAGD operations as well as LPGs for fracking operations.
Synthetic gas liquids have the potential to increase the supply of liquids significantly in Canada. Once again, this opportunity presents additional options for expanded value-added development.
From a buyer’s perspective, risks exist in the markets for butanes and pentanes as they become increasingly tight in supply and high in demand. Diversification of supply and investments in import infrastructure are two ways to deal with this issue. Meanwhile, increased burgeoning supplies from the US can be a part of the solution depending on their local needs. Buyers will need to proactively develop new and diversified supply sources and infrastructure in order to be able to grow demand.
Examples of increasing supply sources of pentanes plus and condensate include the completion of the Southern Lights pipeline (2010), the planned reversal of the Cochin pipeline (2014), as well as the planned diluent line that makes up part of the planned Northern Gateway project. Assuming 100 mb/d of maximum capacity on each of these lines, at full capacity these lines will only provide a portion of the increased required sources of diluent supply as estimated by CERI in this analysis.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 103
Butanes might increasingly become used as a diluent alternative to pentanes plus, but given the limited supply, imports from abroad will be increasingly required. Alternatively, SCO has been used as a diluent but this can be both inefficient and costly, not on its own merit, but rather when compared to other existing options.
Alternatively, given the proper economic and market conditions, further development of upgrading capacity in Alberta will reduce the need for required diluents, regardless of what is used.
Last but not least, opportunities exist for butanes and pentanes plus producers in the WCSB to maximize extraction and marketing within the region to supply increasing demand. While it is possible that this will require further infrastructure development or upgrades these might in turn be added benefits to the local economy and will serve to further develop the local NGLs market.
July 2012
104 Canadian Energy Research Institute
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 105
Chapter 3: Natural Gas Liquids Supply and Demand in the United States –
Forecasting Methodology Natural Gas The methodology for forecasting NGLs supply varied by region depending on the availability of public data that enabled detailed analysis.
Although some analyses were performed at the state or play level in the US, the majority of the analysis was performed at the PADD level. For the United States, CERI did not perform an analysis of the refineries’ role in supply or utilization of NGLs which is particularly important when forecasting butanes and condensate supply demand balances. While historical data is provided for butanes and condensate for reference purposes, CERI forecasts were only provided for ethane and propane.
One of the key findings from the analysis was that with current technology and an adequate gas price, the gas shale resource is such that North America is demand limited, not supply limited for the foreseeable future. The question is largely what gas price is required to balance supply and demand. And the answer to that question will vary over time. In the short term, producers are drilling shale gas wells in dry gas plays even in the current environment where even half cycle costs materially exceed the medium term market price in order to hold petroleum rights to lands acquired over the past few years. This means that so long as producers continue to drill dry gas plays at current low prices, continuation of low gas prices is a reality.
For wet gas plays the economics are on a continuum where in very wet gas plays the economics of a well are carried by NGLs even at low or zero gas prices while moderately wet gas plays are economic at NYMEX gas prices below $3.00/mcf. An additional feature of the market is that while cash flow available for producers to drill gas wells is adversely affected by low near term gas prices, producers are utilizing rising forward curves in their economic evaluations. For example, although Henry Hub spot gas prices are trading below $2.00/mmbtu, the NYMEX Henry Hub forward curve rises to exceed $4.00/mmbtu by 2014 and to $5.49/mmbtu by 2020.1
Figure 3.1 provides the estimated break even economics for a number of shale plays. Some gas plays require prices above $4.00/mmbtu to be economic whereas others are economic at prices as low as $3.00/mmbtu. What the gas price will do is dictate where drilling occurs.
In a sub-$3.50/mcf gas price environment, coalbed methane (CBM), all but the most prolific conventional gas plays, and a few discretionary dry shale gas wells will not be drilled. US gulf offshore gas development will be severely slowed.
1 NYMEX Henry Hub closing prices as at April 3, 2012.
July 2012
106 Canadian Energy Research Institute
Figure 3.1: Comparison of Shale Gas Threshold Economics
Source: Provident Energy2
With prices at current levels US drilling rates in the Haynesville and Fayetteville shales are slowing while in the WCSB development rates for dry gas plays like the Horn River will slow to reach minimum commitment levels. On the other hand, even with current low gas prices the high crude oil price environment is creating a huge incentive to drill either wet gas or oil-based plays.
In the case of the Bakken (North Dakota), each barrel of produced crude oil is associated with approximately 1 mcf of solution gas that is very liquids rich. Should the Bakken crude production continue to rise from recent 500 mb/d levels to in excess of 1,000 mb/d as forecast by some in industry, more than 1 bcf/d of solution gas will be produced in North Dakota. After NGL extraction 1.0 bcf/d of raw solution gas results in approximately 650 mmcf/d of residue gas, representing an amount that exceeds local North Dakota requirements by four times. Similar trends are developing in other oil or liquids-rich plays.
Activity levels in the Eagleford, Niobrara, Permian, Anadarko, and the wet gas portion of Marcellus and Utica plays are high and currently appear to have sufficiently robust growth prospects to offset declines expected in conventional, offshore, coalbed methane and deep dry shale gas plays. These plays are displayed in Figure 3.2.
2 Provident Energy, Analyst Day Presentation, Dividend Income and Growth, October 6, 2011 based on Morgan Stanley data.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 107
Figure 3.2: US Shale Plays
Source: EIA
A combination of public announcements by industry participants and data from companies such as Baker Hughes and SmitBits make it clear that not only are we seeing a relentless march up in oil-directed drilling, but beginning in third quarter 2011, in the face of weakening gas prices, gas-directed drilling showed a significant pull back in active rigs (Figure 3.3). This is a clear indication that gas prices have now reached the point where the economics of drilling gas wells does not support previous activity levels.
Application of technology and processes developed over the 27 years since production first began from the Barnett Shale are being applied across all other shales. Figure 3.4 demonstrates that while it took the Barnett 27 years to achieve 2.6 bcf/d of production it only took 6 years to achieve that rate in the Fayetteville.
The Marcellus has achieved that production rate in even less time. Recent events demonstrate that the gas production industry can aggressively grow supply volumes. Having unlocked the secret to gas production from shales and given the large North American shale resource the actual rate of supply growth will be limited by price, construction of mid-stream facilities and demand.
July 2012
108 Canadian Energy Research Institute
Figure 3.3: Baker Hughes Oil and Gas Directed Drilling Rig Counts
Source: Baker Hughes
Figure 3.4: Accelerated Supply Build-up Fayetteville versus Barnett
Source: Southwest Energy3
3 Southwestern Energy December 2011.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 109
Some 75 percent of North American natural gas liquids are provided by processing natural gas destined for market. NGL supply must be addressed in the context of natural gas production, which in turn is dependent on the available natural gas resource and the demand for natural gas.
Much of the CERI forecast of US NGL supply relies on the US Energy Information Administration (EIA) forecasts and underlying data. Following is a recap of some of the key features of the US natural gas supply forecast.
As a measure of the amount by which sentiment regarding the prospects for US gas supply has changed over the past few years we need only look to how the EIA forecast of US gas production has been revised in its annual updates. To permit a consistent comparison, the EIA’s forecast performed in each of the years 2007 to 2012 for the forecast year 2015 are compared.
As recently as 2007-2010, US dry gas production forecasts for 2015 were in the range of 19.7 bcf/d and forecast US lower-48 wellhead gas prices for 2015 exceeded $5.00/mmbtu. Significant levels of LNG imports were required as the marginal supply source to fill any US supply imbalance. The combination of high prices in 2008 and 2009 together with growing confidence that US shale gas production was not only a substantial resource but also was economic at current prices caused the EIA to begin forecasting increasing domestic US gas supply.
Supply growth exceeded demand growth to the point that the EIA lowered forecast gas prices and caused imports both by pipeline and LNG to decline. US gas supply was proving so competitive that gas supply grew even as gas prices declined. In the most recent update of its forecast the EIA is forecasting that US domestic production for the year 2015 will reach 24.23 Tcf which is a 26 percent increase from its forecast just two years ago (Figure 3.6). The US is well on its way to achieving that forecast level of production. In 2011, actual dry gas production rates amounted to 23 Tcf, just five percent shy of the 2015 forecast.
The following shale gas reserves and resources figures (Figures 3.5 & 3.6) demonstrate that US dry gas resource estimates that were quite stable in the early 2000s have now grown materially reflecting both the growth in proven reserves and the strong additions to unproved resources provided by shale gas.
Production in the Barnett shale paved the way and proved out the technology required to produce shale from many other plays. Barnett production exceeded 1 Tcf for the first time in 2007. It was not until 2008 that meaningful quantities of production from other shale plays appeared proving that technology that worked in the Barnett could be applied in other shale plays allowing resources in other shale plays to be viewed as economically viable (Figures 3.7 & 3.8). With the technology and economic viability confirmed large volumes of shale gas resource were recognized by the EIA.
July 2012
110 Canadian Energy Research Institute
Figure 3.5: US Dry Gas Resource
Source: EIA4
Figure 3.6: Year 2015 Forecast US Gas Supply Provided in Sequential EIA Annual Energy Outlooks with a Comparison to 2011 Actual
Source: EIA AEO5
4 EIA Data for Slides for AEO 2011, with updates for 2012 from AEO 2012 ER. 5 EIA – Multiple AEOs. Source for AEO 2007: EIA Annual Energy Outlook 2007, Table 22. Comparison of natural gas projections, 2015, 2020 and 2030. Source for AEO 2008: EIA Annual Energy Outlook 2008, Table 11. Comparison of natural gas projections, 2015, 2020 and 2030. Source for AEO 2009: EIA Annual Energy Outlook 2009, Table 19. Comparison of natural gas projections, 2015, 2020 and 2030. Source for AEO 2010: EIA Annual Energy Outlook 2010, Table 13. Comparison of natural gas projections, 2015, 2025 and 2035. Source for AEO 2011: EIA Annual Energy Outlook 2011, Table 16. Comparison of natural gas projections, 2015, 2025 and 2035. Source for AEO 2012 ER: AEO 2012 ER http://www.eia.gov/oiaf/aeo/tablebrowser/#release=EARLY2012&subject=0-EARLY2012&table=13- EARLY2012®ion=0-0&cases=early2012-d121011b
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 111
In terms of more recent shale gas volumes, Figure 3.9 identifies that the growth in shale gas volumes continues unabated. Volumes have doubled from 12 bcf/d to 25 bcf/d in the past two years.
Figure 3.7: Estimated US Dry Shale Natural Gas Production, 2000-2010
Source: EIA data6
Figure 3.8: Estimated Annual US Dry Shale Natural Gas Production, 2000-2011
Source: EIA7
6 EIA http://www.eia.gov/oiaf/aeo/gas.html 7 EIA, March 13, 2012 The U.S. surpassed Russia as world’s leading producer of dry natural gas in 2009 and 2010; http://www.eia.gov/todayinenergy/detail.cfm?id=5370#.
July 2012
112 Canadian Energy Research Institute
Figure 3.9: US Monthly Shale Gas Production, 2010-2011
Source: EIA8
Figure 3.10: US Natural Gas Production, 1990-2035
Source: EIA9
8 http://www.eia.gov/naturalgas/weekly/
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 113
During this same time frame, reserves of US gas were rising as were production rates from shale gas plays. Shale gas production increased ten-fold from less than 0.5 Tcf in 2004 to 5 Tcf in 2010. Resource estimates for shale gas were lagging behind the rate at which the industry was developing shale gas plays.
For example, the US Geological Survey increased its economically recoverable resources for the Marcellus from 2 Tcf that was assessed in 2002 to 84 Tcf in its 2011 assessment. However, 84 Tcf was about 20 percent of the quantity of Marcellus resources assessed by INTEK published in July 2011.10 The Marcellus is in early stage development. The book is not yet closed on the quantity of gas that will be produced from the Marcellus.
Refinery Supply of NGLs Historically, refinery supply of NGLs in each US PADD and in Canada was a small share of total NGLs supply. In addition the absolute quantity of NGLs provided by refineries was relatively stable. Refinery supplied NGLs were forecast to continue at recent levels in all markets.
The following section first provides an overview of the historical US lower-48 supply demand balance for each of ethane and propane and then provides a more detailed PADD by PADD analysis and forecast for each of ethane and propane.
Ethane Overview The US market for ethane is driven by two main factors. Firstly, aside from leaving ethane in the gas stream and having it burned as fuel, the only major use is as a petrochemical feedstock in an ethylene cracker. Secondly, ethane is not transported by rail or truck which means that supply sources and end-use markets must be pipeline connected. Ethane is neither currently imported nor exported by the US. Ethane markets and the logistics for getting ethane to markets therefore have long lead times.
One of the substantial transformations of the competitive landscape of international petrochemicals is the improved absolute and relative cost of US produced ethylene using ethane as feedstock.
Figure 3.11 demonstrates the amount by which US ethane competitiveness has improved since 2005 when ethane’s value as fuel when left in the gas stream made it the most expensive source of cracker feedstock in the world to its position today where it is now in the lowest cost quartile for cracker feedstock. As a result of this improvement the North American petrochemical industry is facing a revival not thought possible as little as 7 years ago.
9 EIA AEO 2012 ER: http://www.eia.gov/forecasts/aeo/er/executive_summary.cfm. 10 http://www.eia.gov/analysis/studies/usshalegas/ Table 1. INTEK estimates of undeveloped technically recoverable shale gas and shale oil resources remaining in discovered shale plays as of January 1, 2009.
July 2012
114 Canadian Energy Research Institute
Figure 3.11: US Ethane Re-Emerges as a Globally Competitive Cracker Feedstock
Source: GPCA11
Aggregate US demand for ethane is purely driven by its use as a petrochemical feedstock. With widening spreads between the cost of ethane based ethylene and naphtha based ethylene, US ethane consumption (as provided in Figure 3.12 below) has increased 33 percent from an average of 704 mb/d in 2005-2007 to 933 mb/d in 2011.
This reflects increases in available supply and the burgeoning margins arising from cheap US ethane supplies in comparison to the costs for naphtha supplied to ethylene crackers in the US and elsewhere in the world.
Figure 3.12: US Ethane Demand
Source: EIA data
11 Source: Shale Gas: A New Feedstock Reality, Peter L. Cella, Chevron Phillips Chemical Company LLC, December 14, 2011, presented to Sixth Annual GPCA Forum.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 115
Figures 3.13 and 3.14 illustrate the US regional breakdown for ethane supply and demand. In 2011 PADD III accounted for 93 percent of US ethane demand with PADD II accounting for the remaining 7 percent. PADD II’s ethane consumption occurs at ethylene crackers in Illinois and Iowa. US ethane supply is more broadly distributed, with PADD III representing 62 percent of 2011 US supply at 562 mb/d. PADD II and PADD IV provided 167 mb/d and 179 mb/d, respectively.
Supply in both PADDs II and IV exceeds local market requirements. All surplus ethane is shipped by pipeline to the Gulf Coast either in purity form or as NGL mix. Purity ethane is utilized directly as a petrochemical feedstock while ethane in the form of mixed NGLs or ethane/propane mix are first fractionated to spec products and the resulting ethane then used as feedstock.
As an indication of the current enthusiasm in the industry, Table 3.1 provides a summary of the ethylene plant expansions and announced feasibility studies for new North American plants totaling some 7.7 million tons of ethylene capacity with 6.4 million tons in the lower-48.12
Although all projects are not likely to proceed unless it is abundantly clear that the ethane supply is sustainable, in the long term that amount of incremental ethylene capacity would require in the order of 460 mb/d of ethane feedstock.
Figure 3.13: US Ethane Consumption by PADD Figure 3.14: US Ethane Supply by PADD (mb/d) (mb/d)
Source: EIA data
12 The Oil & Gas Journal (OGJ) estimates current (2012) ethylene production capacity in the US at over 30 million tons.
July 2012
116 Canadian Energy Research Institute
Table 3.1: North American Capacity Ethylene Expansion
NA Ethylene Expansion "Talk" In The Press ~ 7.66 Million Tons
Company 2012 2013 2014 Future Announced (-000-MT) Chevron Phillips (TBD) 1500* Dow (Taft/TBD) 193 193 1300* Equistar (All locations) 130 100 Formosa (Point Comfort) 800 Uneos (Chocolate Bayou) 57 58 Oxy (Ingleside, TX) 550* Shell (Northeast) 1000* Westlake (Lake Charles) 30 110 80 Williams (Geismar) 27 70 210 NOVA (Sarnia) 250* Braskem/Idesa (Mexico) 1000 Total 244 531 483 6400 Cumulative Total 244 775 1258 7658 Source: PFAA13
Propane Overview In the case of propane, the market is much more dynamic than the ethane market. In addition to movements of propane by pipeline, propane moves by truck, rail and barge and in the case of overseas imports and exports, by ship.
The propane market is much less dependent on pipeline connections than the ethane market. While a portion of the market for propane serves transportation and petrochemical needs the bigger part of the market is for heating. As a result the demand for propane is very seasonal. Figure 3.15 demonstrates that winter peak demand is roughly double summer demand. That volume swing arising from seasonality of demand is handled by a combination of storage injection and withdrawal and an increase of imports from Canada in the winter.
In terms of supply US gas plant production, propane/propylene is rising, having increased 23 percent from 503 mb/d in 2005-2007 to 618 mb/d in 2011. This increase reflects the combination of improving fractionation spreads that encourage capital investment to increase the recovery of propane entrained in the gas stream and the additional production of liquids- rich gas supplies.
1313 Source: Pinch Me, I Think I’m Dreaming, North American Olefins Overview, Chuck Carr, CMAI presented to PFAA – Austin TX, November 20, 2011
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 117
Refinery production of propane/propylene is roughly constant at 550 mb/d showing little year over year variation.
Figure 3.15: US Propane/Propylene Consumption
Source: EIA data
Propane imports shown in Figure 3.16 are highly seasonal however they have been declining throughout this period reflecting a combination of reduced availability from Canada and increasing local supply. Propane imports averaged 214 mb/d in 2005-2007 decreasing 50 percent to 108 mb/d in 2011.
Figure 3.16: US Propane Supply
Source: EIA data
July 2012
118 Canadian Energy Research Institute
Figure 3.17: US Propane/Propylene Imports
Source: EIA data
As demonstrated in Figures 3.18 and 3.19, PADD III supplies more than 60 percent of domestic production while representing only 50 percent of demand. PADD II, the second largest producing region provides approximately 20 percent of supply while representing 26 percent of demand. PADD I consumes about 16 percent of US propane/propylene while only producing 5 percent of supply.
Figure 3.18: US Propane/Propylene Demand Figure 3.19: US Propane/Propylene Supply (mb/d) (mb/d)
Source: EIA data
PADDs I and II are short supply on an annual basis and require transfers from PADDs III and IV to balance their markets. The majority of these transfers take place in the winter to meet peak winter heating demand.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 119
Until recently the US was a net importer of propane during all months of the year. That changed in 2010. Propane exports that averaged 42 mb/d in 2005-2007 increased to 124 mb/d in 2011. In 2011 the US became a net exporter of propane. These exports primarily occur from PADD III reflecting that the Gulf Coast market for propane/propylene was not large enough to absorb the increased supply that was a combination of increasing PADD III supply and transfers from PADDs II and IV. Figure 3.20 demonstrates the growth in export volumes, while Figure 3.21 demonstrates the rapid shift from being a year round net importer to a seasonal exporter of propane.
Figure 3.20: US Propane/Propylene Exports
Source: EIA data
Figure 3.21: US Propane Imports Less Exports
Source: EIA data
July 2012
120 Canadian Energy Research Institute
The projected large growth in the supply of NGLs requires a concomitant increase in fractionation capacity to effectively turn available NGL supply into spec products.
Aggregating projects under construction with planned projects indicates that fractionation capacity will expand more than 50 percent from 2.2 million b/d in early 2011 to 3.4 million b/d by 2014. Expanded fractionation capacity is being backed by long term producer commitments indicating high levels of confidence that the NGLs required to fill that incremental fractionation capacity is in fact available.
The two areas showing the largest increase in capacity are PADD I indicating the strength of the wet gas portion of the Marcellus play and in Texas reflecting the combined impact of local liquids rich gas supply growth and NGL transfers to Texas from PADDs II and IV. Incremental PADD I NGL fractionation capacity (under construction and announced) amounts to some 310 mb/d while incremental PADD III capacity amounts to 870 mb/d. Capacity increases by PADD are shown in Figure 3.22.
Figure 3.22: US Fractionation Capacity Existing & Planned
Source: Industry announcements
A more detailed historical supply and demand forecast in each of the PADDs will be described in the next section combined with the generation of a long term forecast of each of supply and demand.
PADD by PADD Overview and Forecast
PADD I: East Coast PADD I encompass the entire US east coast accounting for a total of 18 states from Florida to Maine (see Appendix A for a map of the US PADDs). In the past, PADD I was primarily an energy consumption (demand) region, although some gas and liquids were produced in Pennsylvania, West Virginia and Ohio.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 121
With the emergence of the Marcellus gas play since 2005 and the prospect for a growing impact from the Utica play, PADD I is already a substantial natural gas supplier and promises to have an even greater impact in the future. In addition to the impact gas production is having on the gas market, PADD I gas supply is also having an impact on the North American liquids market.
Natural gas produced from the Marcellus in southwestern Pennsylvania and northern West Virginia is wet (liquids-rich), and initial indications are that Utica production, today primarily produced in Ohio is also wet gas.
Traditionally PADD I was a large net natural gas liquids consumer, importing volumes from Canada, and PADDs II and III. As the Marcellus and Utica develop, PADD I is reducing its import requirements and in the case of ethane projected to become a significant net exporter.
Much like the question regarding the total size of the impact Bakken production will have on the market there is a question of the potential magnitude of the combined Marcellus and Utica resource and the production rates that these plays will support.
The USGS has recently placed a technically recoverable resource estimate of 84 Tcf for these. That estimate was based on production and drilling data to the end of 201014 and is in addition to amounts already booked as proven reserves by industry participants at the time the study was undertaken.
The EIA initially accepted a technically recoverable resource estimate of 410 TCF for the Marcellus, produced by INTEK,15 but has since revised its estimate of the Marcellus resource down from 410 Tcf to 141 Tcf. In support of a reserves estimate that exceeds the USGS estimate of 84 Tcf, the EIA argues that new information that became available in 2011 and the addition of proven reserves justifies increasing its resource estimate above that of the USGS.16
So how much production could this size of resource support? To help put this relationship into perspective, Figure 3.23 identifies a hypothetical development profile where industry aggressively pursues a resource development plan with timely investment in wells, gathering pipelines, gas processing plants, fractionation facilities and mainline transmission pipelines for a resource equal to 141 Tcf.
Additional assumptions are made that result in the available supply flat lining for a period of time and then going into decline. The flat line section of the production profile recognizes that most assets constructed to develop a natural gas resource are both long life and highly capital intensive. The flat portion of the production profile reflects that the industry will attempt to optimize capital deployed for pipelines and processing plants consistent with its estimate of the resource availability to attempt to achieve minimum acceptable returns on capital employed.
14 EIA AEO2012 Early Release Overview. http://www.eia.gov/forecasts/aeo/er/pdf/0383er(2012).pdf 15 EIA Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays, July 2011, pg 5 16 EIA AEO2012 Early Release Overview. http://www.eia.gov/forecasts/aeo/er/pdf/0383er(2012).pdf
July 2012
122 Canadian Energy Research Institute
Using a 60 year development and production scenario a 141 Tcf resource supports a production profile that peaks in the 12 bcf/d range.17
Figure 3.23: Example Development Scenario for a 141 Tcf Gas Resource
Source: CERI analysis
The EIA provides the forecast shown in Figure 3.24 for natural gas production in the northeast US. All northeast production falls within PADD I.
The EIA forecast slows down the recent fast supply build up, and then extends production growth throughout the entire term of the 25 year forecast. Combining shale and non-shale gas resources in the Northeast permits the EIA to build production to over 15 bcf/d by 2035.
The Marcellus and Utica shales are complex, with certain areas producing relatively dry gas and others producing liquids-rich gas, and in the case of the Utica, also producing crude oil in some areas. Liquids, particularly propane, butanes and pentanes plus currently trade at a significant premium to the btu value of those same liquids if left in the gas stream.
Although ethane currently trades at a premium to its btu value in the gas stream in Gulf Coast markets that is not always the case and the premium varies by markets.
17 The actual peak production rate is strongly influenced by the assumed rate of production build up, the length of the flat production period and the decline rate once the basin goes into decline.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 123
Figure 3.24: EIA Forecast Northeast Gas Production
Source: EIA18
Northeast producers began development in both northeast Pennsylvania, where the Marcellus produces dry gas, and in southwest Pennsylvania, where the Marcellus produces wet gas. The weight of gas supply additions across North America exceeding demand growth caused natural gas prices to fall across the continent. These price reductions were sufficient to even affect supply development so close to the market as the dry gas region of the Marcellus in northeastern Pennsylvania.
Over the course of 2011, particularly in the latter half of the year and continuing into 2012 dry gas producers reprioritized drilling activity to only that required to hold previously acquired leases and meet other contractual obligations while shifting discretionary expenditures into wet gas areas in North America including the wet gas portion of the Marcellus and the Utica.
Following is an example indicatively showing the impact of wet gas production revenue at various levels of liquids content compared with dry gas production revenue. In some cases the liquids content is sufficient to fully support the drilling activity. As is evident from Figure 3.25, rich gas liquids revenues can more than double the value that can be achieved by dry gas production alone. The liquids-rich gas premium is important in forecasting how activity levels in the Northeast will translate to gas production and in turn translate to liquids production.
18 EIA, AEO 2012 Table ref2012.d121011b
July 2012
124 Canadian Energy Research Institute
Figure 3.25: Comparison of Revenues for Dry and Wet Gas Production
Source: CERI analysis
A number of gas producers have recently announced capital budget curtailments and redirection of available funds into wet gas areas. For the Marcellus this means that more resources will be focused on the southwest corner of Pennsylvania and northern West Virginia. It also means that the Utica in Ohio is receiving more attention which will accelerate the pace at which the industry proves up its potential. The reduction in drilling activity in northeast Pennsylvania will permit infrastructure development to catch up with the recent high rate of production growth and will also reduce competition that gas from the rich gas developments faces in penetrating markets.
From an NGL forecast perspective this means that construction of NGL infrastructure will be front and center. A number of NGL related projects are under construction and others have been announced.
The Marcellus transitions from a dry gas play in the Northeast to a wet gas play in the Southwest. Liquids entrained in the gas stream vary throughout this transition and even within the wet gas region itself. To estimate gas plant liquids production, CERI split the EIA forecast of Northeast gas supply into two broad categories; wet and dry, and then assigned recoverable liquids ratios to the wet gas portion of that forecast. This approach produces an estimate of gas plant liquids available to be extracted.
Not all available liquids will be immediately produced as gas processing and fractionation facilities have long lead times and are playing catch-up to the rate at which gas wells are being drilled and brought on stream. To the extent that the resulting liquids-rich gas can be blended with drier gas before reaching market, a significant portion of the available liquids will not be extracted from the gas stream in the short term. Over the next two to three years, sufficient natural gas liquids infrastructure will be commissioned to produce gas plant liquids forecast to be available.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 125
Ethane Of particular interest is the rate at which ethane will be produced and marketed. Ethane has no local market and it cannot be economically trucked or railed. It is pipelined. Some wet gas contains so much ethane that a portion must be removed just to meet pipeline specifications. With no local market for ethane, several pipeline projects have been proposed to move ethane out of the area.
One project, Mariner West,19 is a 50 mb/d project to move ethane from the Marcellus to Sarnia, Ontario for feedstock in NOVA Chemicals Sarnia cracker using a combination of re- purposed refined products pipelines and new pipe. NOVA Chemicals has announced capital expenditures to permit the cracker to accept a larger volume of ethane as feedstock.20 This project is expected to be on stream in mid-2013.
Further volumes of ethane can be imported from the northeastern US to Ontario as Imperial Oil Chemicals has indicated that in 2011 they signed a long-term supply agreement for Marcellus sourced ethane for their Sarnia Chemical plant.21. CERI estimates that both of these Ontario ethylene crackers together (NOVA and Imperial Oil) could absorb a maximum of 72 mb/d of ethane, which corresponds to the maximum capacity of 70 mb/d which can be reached by the Mariner West project.22 However, CERI has used the 50 mb/d volume moving from PADD I to Ontario, as Imperial Oil Chemicals sources some of its supply from its own refinery off-gases , and, depending on their intended product skate, NOVA Chemicals may wish to maintain some heavier NGLs available as a feedstock..
A second pipeline project is Enterprise’s Appalachia to Texas pipeline (“ATEX Express”)23 that is sized at 190 mb/d and would transport ethane from southwest Pennsylvania to the US Gulf Coast. It passes through the wet gas portion of West Virginia. In January 2012 Enterprise announced that it had sufficient shipper commitments to proceed with the project. ATEX Express involves a combination of new pipe to Cape Girardeau, Missouri. From Cape Girardeau, Enterprise will reverse an existing 16 inch diameter pipeline and place it into ethane service. In the market area ATEX will build some additional new pipe to tie the ethane supply into the Mont Belvieu area. This pipeline option is to be on stream by the first quarter of 2014.
A third alternative involves the creation of local ethane demand by building an ethane cracker and an associated downstream petrochemical complex.
19 Mariner West is a MarkWest Liberty Midstream & Resources LLC and Sunoco Logistics Partners L.P. joint venture, Sept 7, 2011, www.downstreamtoday.com/news/article.aspx?a_id=27797 20 See: NOVA Cehmicals – Form 20-F: http://www.NOVAchem.com/ExWeb%20Documents/investor- center/20F_2011_NCC.pdf 21 Imperial Oil’s 2011 Annual Report: http://www.imperialoil.ca/Canada-English/Files/2011_AR.pdf 22 See: Oil & Gas Journal article: http://www.ogj.com/articles/print/vol-110/issue-5/special-report-worldwide- gas/us-ngl-pipelines-expand.html 23 Enterprise Products Partners L.P., Enterprise to Build Marcellus/Utica Shale Ethane Pipeline, Jan 3, 2012
July 2012
126 Canadian Energy Research Institute
Shell has optioned some property in the Appalachian region while it studies the development of an ethylene, polyethylene and mono-ethylene glycol complex.2425 Building a full scale petrochemical complex would require a number of years to develop and an in-service date is unlikely to be before 2016. Minimum scale for one of these complexes would require in the range from 60 to 90 mb/d of ethane.
Together the Mariner West and ATEX Express pipeline project will have at least 240 mb/d of capacity. The following two examples are provided to provide some perspective for the amount of liquids rich gas that must be available to supply 240 mb/d of ethane pipeline capacity.
Ethane in the wet gas portion of the Marcellus play can be as high as 15 percent of the raw gas stream.26 Optimistically, 90 bbls/mmcf of ethane can be recovered from gas with 15 percent ethane assuming a 93 percent recovery rate, which means that it would require production of 2.7 bcf/d of high ethane wet gas to fill the two currently proposed pipelines. To meet the requirements of those two pipelines and also meet the requirements of a petrochemical complex would require an additional 800 mmcf/d of high ethane rich gas for a total of 3.4 bcf/d. If, on the other hand, the average gas composition in the wet gas region was 10 percent ethane, it would then take 5.5 bcf/d of wet gas to meet the requirements of both pipelines and a local ethane based petrochemical complex.
Rather than perform an independent forecast of Northeast gas supply, this study has accepted the EIA AEO 2012 gas supply forecast27which is then subdivided into a wet gas and dry gas component. Recoveries of gas plant liquids from the gas streams are assumed as the basis for producing the gas plant liquids forecast. Given the EIA forecast of gas production in the Northeast that reaches 9 bcf/d by 2020 and recognizing that only a portion of the produced gas will be wet gas, it will be some time before both ethane pipelines would be full, let alone produce sufficient ethane to fill both pipelines and provide the supply required to support a local ethane based petrochemical industry.
Figure 3.26 highlights that even with the recent strong economic incentive to preferentially develop liquids rich gas, the rate at which drilling continues in the dry gas portion of the Marcellus is high. The down trend in drilling rigs active in the dry gas portion of the Marcellus is beginning; however, the rig count is high enough to more than sustain already existing production levels. The number of drilling rigs in the wet gas portion of the Marcellus within Pennsylvania is rising but only very slowly.
24 http://www.shell.com/home/content/chemicals/aboutshell/our_strategy/marcellus_cracker_project/ 25 Cracking of ethane produces ethylene which has similar transportation issues. Today, there is no local market for ethylene. Ethylene needs to be upgraded to bulk petrochemicals. An ethylene cracker will only be built in conjunction with the derivative petrochemical complex that permits the ready transport of any resulting products 26 http://www.ogj.com/articles/print/volume-107/issue-10/special-report/compositional-variety-complicates- processing-plans-for-us-shale-gas.html 27 Source: EIA, AEO 2012 Table ref2012.d121011b
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 127
Given the strong near term monetary incentive to develop and produce wet gas the study assumes that wet gas production will preferentially build up in the near term while dry gas production stabilizes in 2012 and 2013 as shown in Figure 3.27.
Then, later in the forecast dry gas production provides more of the growth. The gas plant liquids forecast superimposes development of facilities to extract and fractionate the liquids into specification products on the wet gas production rate.
Figure 3.26: Pennsylvania Wet and Dry Gas Rig Counts
Source: Smith Bits28
Figure 3.27: PADD I Gas Production with Wet Dry Gas Split
Source: EIA historical data, CERI Analysis
28 Rig data reports rig location by County, CERI identified wet and dry gas counties in Pennsylvania (http://stats.smith.com/new/history/statshistory.htm)
July 2012
128 Canadian Energy Research Institute
Converting a natural gas production forecast to a gas plant NGL forecast involves estimating the NGLs entrained in the gas stream and then estimating the portion of entrained NGLs that will be recovered.
Several individual gas analyses have been reported indicating that the wet gas portion of the Marcellus production contains from 75 to 100 bbl/mmcf of ethane and from 35 to 70 bbl/mmcf of C3+ NGLs.29 MarkWest provides a description of its Marcellus NGL gas processing, de- ethanization and fractionation business, including the Houston, Majorsville, Mobley and Sherwood processing complexes suggesting that 75 mb/d of de-ethanization capacity and 60 mb/d of C3+ fractionation capacity match up with 1.1 bcf/d of raw gas processing capacity. This implies expected production of approximately 65 bbl/mmcf of ethane and 52 bbl/mmcf of C3+.30 Given that the MarkWest assets cover a significant portion of the wet gas portion of the Marcellus from Pennsylvania to West Virginia, the study has used these values in forecasting gas plant NGLs produced from the wet gas portion of the Marcellus.
As at year-end 2011 no meaningful quantities of ethane were either produced or consumed in PADD I reflecting that only very limited amounts of ethane will be recovered before ethane pipelines move gas out of PADD I and associated de-ethanization facilities are constructed. On- stream dates are expected by 2013. Even high-efficiency extraction facilities operating under optimal conditions will only recover about 92-93 percent of the ethane available in the gas stream31 which means that industry wide recovery rates will be somewhat lower. The study is forecasting that ethane production will quickly ramp up to 162 mb/d in 2015 and then gradually increase to 272 mb/d over the remainder of the forecast period.
Given this ethane volume forecast, ethane feedstock required to satisfy a PADD I ethane cracker prior to 2025 would need to come at the expense of fully utilized capacity on either one or both of the ethane pipelines (Mariner West or ATEX).
An ethane cracker built on the timeline proposed by Shell (2016) would need to compete for ethane supply with ethane markets in the Gulf Coast and Sarnia or wait until local supply increases in the order of 250 mb/d. This forecast assumes that a local ethane cracker with 75 mb/d capacity is created in 2019 and assumes exports to Sarnia, Ontario of 45 mb/d. Remaining volumes are shipped to the Gulf Coast. The combination of one ethylene cracker, a 50 mb/d export pipeline to Canada and 150 mb/d of pipeline capacity to the Gulf Coast would be sufficient to move all available ethane produced by this forecast.
The following section provides the PADD I propane/propylene recent history and long term forecast.
29 Infrastructure Projects Connect Marcellus Shale to Ethane, NGL Markets, March 2011, E. Russell “Rusty” Braziel. 30 MarkWest Liberty Project Mariner, Platts Midstream & Development Conference, Oct 21, 2011 31 Industry conversations: Efficient plant can recover ethane to the point where 0.7 mole percent of gas remains in the gas stream, resulting in 93% efficiency if the raw gas ethane content is 10% of the gas stream. Forecast is constructed assuming an industry average 85% recovery factor.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 129
Figure 3.28: PADD I Ethane Production from Wet Gas Play
Source: CERI analysis
Figure 3.29: PADD I Ethane Supply Demand Forecast
Source: CERI analysis
Propane Some small gas processing facilities existed in PADD I to process non-Marcellus gas being produced. C3+ production amounted to approximately 20,000 bbl/d in 2009 and has slowly begun to rise in 2011 reflecting the impact of small plant expansions and the first newly constructed gas plants coming on stream.
July 2012
130 Canadian Energy Research Institute
C3+ production is not dependent on ethane pipelines and de-ethanization capacity and the resulting products can be transported to market by truck and rail. Recoveries are estimated at 50 percent in 2012 increasing to 98 percent over time as gas processing and fractionation facilities construction catches up with wet gas supply volume growth.32
As shown in Figure 3.30 forecast C3+ volumes quickly grow from 57 mb/d in 2012 to 142 mb/d by 2015 and then grow more gradually to 246 mb/d over the remaining forecast period.
Figure 3.30: PADD I Gas Plant C3+ Production from Wet Gas Play
Source: CERI analysis
Figure 3.31: PADD I Fractionated Gas Plant NGL Production from Wet Gas Play
Source: CERI analysis
32 Substantially all liquids rich gas will be processed for ethane extraction which facilitates very high propane recovery rates.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 131
Propane production is forecast to increase to 82 mb/d by 2015, while butanes and pentanes plus increase to 33 mb/d and 27 mb/d, respectively. Those volumes then further increase to 143 mb/d, 57 mb/d and 47 mb/d, respectively by the end of the forecast period (Figure 3.31).
In addition to liquids produced at gas plants, refineries also produce NGLs. On a monthly basis refinery produced propane and propylene has ranged from approximately 40 mb/d to 75 mb/d. For the purposes of this study CERI has not independently forecast refinery based propane and propylene production. Instead CERI has assumed that production continues at 60 mb/d for the term of the forecast. Any discontinued refinery operations in PADD I would cause this forecast to be overly optimistic.
PADD I propane demand has averaged approximately 200 mb/d over the period 2005-2011. Less than one-third of that total is supplied locally with refinery supply averaging about 45 mb/d and gas plant supply reaching 19 mb/d in 2011. The remainder is either imported or transported to PADD I from other US regions.
The Northeast uses propane for heating which results in a very seasonal demand profile. Demand drops as low as 100 mb/d in the summer and can exceed 350 mb/d in the winter. The EIA forecasts total LPG demand to remain roughly flat. This forecast has assumed that PADD I propane demand escalates at 0.5 percent per annum beginning in 2013. Even with such a low demand growth PADD I can, on average, absorb all of the propane supply that is forecast to become available while displacing a combination of imported supply and transfers from PADDs II and III.
Figure 3.32: PADD I Propane/Propylene Supply Sources
Source: EIA data
July 2012
132 Canadian Energy Research Institute
As shown in Figure 3.33, PADD I gas plant propane production is forecast to grow from under 20 mb/d in 2011 to over 140 mb/d by the end of the forecast period, while refinery production of propane/propylene is held constant at 40 mb/d. Propane is forecast to grow to the point where only a small quantity of Canadian imports and transfers from other regions totaling 30 mb/d are required to balance the PADD I market; a reduction of roughly 100 mb/d from 2011 levels.
Figure 3.33: PADD I Propane/Propylene Supply Demand Forecast
Source: CERI analysis
PADD II: Midwest PADD II encompasses the following states; Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, South Dakota, Ohio, Oklahoma, Tennessee, and Wisconsin.
PADD II encompasses both the prolific Bakken/Three Forks oil play primarily in North Dakota and the Cana Woodford play in Oklahoma. CERI has analyzed the North Dakota Bakken/Three Forks play in some detail on the basis of available state data and has analyzed the remainder of PADD II at an aggregated level based on EIA data.
Bakken/Three Forks The size of the Bakken resource is currently under question.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 133
The USGS increased its 1995 estimated recoverable oil volumes of 151 million barrels to a range of 3.0 to 4.3 billion barrels in its 2008 review.33 Over the period 2005 to 2007 average oil production in North Dakota was 110 mb/d and has since grown by some 395 percent to 546 mb/d in January 2012.
Industry activity levels in the Bakken seem to be outpacing the activity that would be expected if the actual recoverable resource was in fact only 3 to 4.3 billion barrels. For example, if 2012 average production averaged 546 mb/d (which is equal to January 2012’s production rate) and then went into an annual decline of 7 percent North Dakota would produce 2.9 billion barrels of oil.
On the other hand, and if consistent with some industry forecasts referenced below, production grows to 1.1 million barrels per day by 2020 and then goes on a 7 percent decline, North Dakota would produce in the range of 8 billion barrels of oil, roughly two times the higher end of the USGS estimate for the Bakken. It appears that the USGS is playing catch-up with the impact that new information and new technology is having on the development of the Bakken resource.
The potential upside to the Bakken resource is enormous, and the science of those estimates somewhat controversial. For example, in an article published on the North Dakota Industrial Commission website34 that surveyed the range of Bakken reserves estimates, Bakken recoverable reserves by one estimate were “between 271 and 503 BBbls of oil with an average of 413 BBbls”.35 At its average the estimate would be 100 times the high range estimate for the USGS’ 2008 study.
In a recent presentation, summarized in Figure 3.34, the North Dakota Department of Mineral Resources provided a proven reserve estimate of 7 billion barrels with probable and possible at 10 and 14 billion barrels, respectively.
This study does not estimate the Bakken resource, but does need to ensure that the forecast of production volumes is consistent with a view on the available resource. CERI has somewhat arbitrarily chosen for its forecast a development scenario where North Dakota and Eastern Montana36 combined have resources capable of producing in the range of 10 billion barrels of oil. This scenario has the North Dakota and Eastern Montana production growing to 1.1 million b/d by 2020, remaining flat for several years and then going into decline.
33 USGS, 3 to 4.3 Billion Barrels of Technically Recoverable Oil Assessed in North Dakota and Montana’s Bakken Formation—25 Times More Than 1995 Estimate, April 2008 34 Bakken Formation Reserve Estimates, http://www.nd.gov/ndic/ic-press/bakken-form-06.pdf 35 IBID, page 4 36 Eastern Montana is included to reflect that the Bakken play extends into Eastern Montana and that from an infrastructure perspective is close enough to North Dakota’s infrastructure that produced oil can be combined.
July 2012
134 Canadian Energy Research Institute
Figure 3.34: North Dakota Forecast of Future Oil Production Scenarios
Source: North Dakota Department of Mineral Resources37
Development of the oil shale plays impacts North American natural gas supply. In the case of the Bakken, solution or associated gas is produced in conjunction with crude oil production. The economics of drilling the Bakken in the current crude oil price environment are such that even if the produced solution gas is flared the oil wells are still very economic. Construction of facilities to process natural gas and pipelines to gather solution gas from wells is lagging behind the growth in oil production. That said, new processing facilities have come on stream in late 2011 and early 2012 and more facilities are under construction.
Figure 3.35 compares historical North Dakota crude oil and raw natural gas production. Raw gas production is highly correlated with crude oil production. Each barrel of crude oil is produced with 1.07 mcf of raw natural gas.
With new crude oil wells coming on stream at a faster rate than the associated gas is connected to gas processing facilities, North Dakota producers have been flaring increasing amounts of gas. Figure 3.36 displays the buildup in produced gas along with flared and gas sold. The category of field use and flared is now mainly flared gas reaching 251 mmcf/d in April 2012.
Recent completion of the 100 mmcf/d OneOk Garden Creek facility and 150 mmcf/d expansion of the Hess Tioga facility will increase the amount of produced gas that is processed.
37 Pierce County Farm Bureau Presentation, 03-15-2012, Slide 26, https://www.dmr.nd.gov/oilgas/presentations/PierceCoFarmBureau2012-03-15.pdf
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 135
Table 3.2 presents a list of existing, under construction and announced gas processing plants in the Bakken.
Figure 3.35: North Dakota Daily Oil and Gas Production
Source: North Dakota Department of Mineral Resources
Figure 3.36: North Dakota Gas Production
Source: North Dakota Department of Mineral Resources
July 2012
136 Canadian Energy Research Institute
Table 3.2: Existing, Under Construction and Announced Gas Processing Plants in the Bakken
Owner Location/Name County Volume Status mmcf/d Bear Paw / OneOK Lignite Burke 6.0 Existing Bear Paw / OneOK Marmath Slope 7.5 Existing Bear Paw / OneOK Garden Creek McKenzie 100.0 Existing Bear Paw / OneOK Stateline I Williams 100.0 Q3 2012 Bear Paw / OneOK Stateline II Williams 100.0 Mid 2013 Petro Hunt Little Knife Billings 32.0 Existing True Oil Red Wing Creek McKenzie 4.0 Existing Sterling Energy Ambrose Divide 0.5 Existing Whiting Oil & Gas Robinson Lake Mountrail 90.0 Existing Whiting Oil & Gas Ray Williams 10.0 Existing Whiting Oil & Gas Pronghorn Stark 30.0 Existing XTO - Nesson Ray Williams 10.0 Existing Bear Paw / OneOK Grasslands McKenzie 100.0 Existing Hess Tioga Williams Tioga Williams 250.0 Existing Hiland Partners Badlands Bowman 40.0 Existing Hiland Partners Norse Divide 25.0 Existing Hiland Partners Watford City McKenzie 50.0 Existing Saddle Butte Watford City McKenzie 45.0 Existing Aux Sable38 Palermo Mountrail 100.0 Existing Total 1,100.0 Source: North Dakota Government39
As is evident from the list which totals 1.1 bcf/d of processing capacity the industry is positioned to process a more than doubling of associated gas. Once the two additional OneOk Stateline facilities are in place gas processing will be limited by raw gas gathering infrastructure. In some cases it will be uneconomic to connect gas from isolated crude oil wells to gathering infrastructure. Gas from those wells will continue to be flared.40
Given the resource base, proven technology and very supportive economics, expansion in the Bakken/Three Forks play will continue. Analyst Raymond James is forecasting that Bakken production will rise to 1.2 million barrels per day, while Enbridge is forecasting 1.0 million barrels per day production by 2016.
38 Aux Sable owns the Prairie Rose facility. However, the gas is transported to Alliance Pipeline for processing at the Aux Sable facility in Channahon, Illinois. 39 Available at: http://www.nd.gov/ndic/pipe/publica/annual-report11.pdf and trade press 40 North Dakota permits flaring of gas, however it does require payment of royalties on flared gas one year after the well is on stream.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 137
Given the historical relationship between crude oil and associated gas production, these crude oil production forecasts imply raw gas production ranging from 1.0 to 1.2 bcf/d by 2016. OneOk has indicated that these natural gas streams contain in the order of 250 bbl/mmcf of NGLs41 which implies availability in excess of 250 mb/d.
Figure 3.37: Industry Forecasts of Bakken Production
Source: Enbridge42
North Dakota has historically only produced small quantities of NGLs. Figure 3.38 shows that NGL production has never exceeded 25 mb/d. As a result North Dakota does not have the infrastructure required to pipeline NGLs to market. NGLs currently move by truck and by rail.
While truck and rail transportation is adequate for moving moderate quantities of C3 plus, pipelines are required to market ethane. OneOk has proposed the Bakken NGL pipeline that would run south in the vicinity of the North Dakota/Montana border and interconnect with the OneOk/Williams jointly-owned Overland Pass pipeline.
41 OneOk Investor Presentation, April 3, 2012 indicated that NGL content was in the range of from 8-13 gallons per mcf, which equates to a range of from 190 to 310 bbl/mmcf. 42 Source: http://www.enbridgepartners.com/WorkArea/downloadasset/15440/2012-01-EEP-Earnings-Guidance- FINAL.aspx
July 2012
138 Canadian Energy Research Institute
Figure 3.38: North Dakota Gas Processed and NGL Production
Source: North Dakota Department of Mineral Resources
The Overland Pass pipeline is currently being expanded to handle incremental y-grade NGLs for delivery into fractionation facilities in Conway and Bushton, KS. The proposed Bakken NGL pipeline would have a capacity of 60 mb/d. The line is a y-grade line and would be able to move any ethane extracted at the gas plants.
A second pipeline project is proposed by Vantage Pipeline and would move specification ethane from Hess’s Tioga gas plant to Empress, AB where it would then be delivered to the Alberta petrochemical business using the AEGS system.
The Vantage Pipeline has a 40 mb/d initial capacity with potential to expand to 70 mb/d. Vantage Pipeline would need to gather ethane from facilities beyond the Tioga plant to reach even its initial capacity. That additional ethane could either come from North Dakota or from processing associated gas in the Saskatchewan portion of the Bakken.
To construct its forecast for North Dakota NGLs, CERI has assumed that crude oil production will increase to 1.1 million b/d by 2019 with associated gas production of 1.1 bcf/d as shown in Figure 3.39.
Given the lag being experienced to build NGL extraction facilities and tie in new associated gas production the forecast assumes that some gas will be flared throughout the period. Processed volume increases to 700 mmcf/d by 2015 with a further increase to over 1 bcf/d by 2019. Given the high NGL content in the raw gas stream, produced dry gas will amount to between 65 and 75 percent of the processed raw gas. The forecast of dry gas production shown in Figure 3.40 accounts for NGLs produced and shows a noticeable reduction in late 2013 as the ethane and NGL pipelines come on stream.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 139
Figure 3.39: North Dakota Crude Oil and Raw Gas Production43
Source: CERI analysis
Figure 3.40: North Dakota Raw Gas Production Forecast
Source: Historical data from North Dakota Department of Mineral Resources, CERI analysis
Ethane and Other NGLs Given the lack of pipeline infrastructure to move NGLs from North Dakota, NGLs available at plants other than the Aux Sable Palermo plant will initially move by rail and/or by truck.
43 Source: History, North Dakota Department of Mineral Resources
July 2012
140 Canadian Energy Research Institute
Volumes at Aux Sable’s plant will be shipped as a wet gas to Alliance pipeline and then processed at Aux Sable’s plant in Illinois.
Based on announced schedules both Vantage Pipeline’s ethane line and OneOk’s Bakken NGL pipeline are to be completed in 2013. For forecast purposes each one is assumed to be complete in Q4 2013. With the start-up of these two pipelines, ethane movements will become significant.
Figure 3.41: North Dakota Ethane Shipments
Source: Historical data from North Dakota Department of Mineral Resources, CERI analysis
Consistent with the increasing crude production volumes and reduction in flared gas volumes overall NGL volumes show a steady increase over time. Figure 3.42 shows the NGL components produced.
With the OneOk Bakken pipeline operating as a y-grade pipeline much of the NGLs produced in North Dakota will exit as an NGL mix stream. The volume transported on the Bakken NGL pipeline will increase supplies of NGL mix in the Conway market area.
One of the challenges for the Vantage Pipeline is that the Tioga Hess plant, even when operating at full capacity, will only supply approximately 32 mb/d of ethane44. Vantage Pipeline needs to connect additional gas plants, such as the proposed Plains Ross plant, in order to collect enough ethane volumes to fill the initially proposed pipeline.
44 CERI estimates.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 141
Since Vantage is currently identified as a specification ethane pipeline it will need to access additional supplies at plants that have installed a de-ethanizer. With OneOk planning to move a y-grade mix down the Bakken NGL pipeline it does not need to install a de-ethanizer at any of its facilities.
If a de-ethanizer was installed at any of its facilities and Vantage was connected to the plant then Vantage would be in a pure competition with Gulf Coast ethane prices to fill its pipeline. CERI has not performed a competitive analysis to identify the circumstances under which Alberta petrochemical producers would produce ethane prices high enough to compete for ethane that would otherwise have a market in the Gulf Coast.
Figure 3.42: North Dakota NGL Shipments
Source: Historical data from North Dakota Department of Mineral Resources, CERI analysis
Remainder of PADD II The remainder of PADD II includes the following states; Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, South Dakota, Ohio, Oklahoma, Tennessee, and Wisconsin.
The supply of gas from which liquids can be extracted in PADD II comprises both local production and the liquids-rich gas stream that is imported to the Chicago area on Alliance pipeline. Alliance’s pipeline capacity is about 1.6 bcf/d. With the forecast high fractionation margins it is expected that Alliance will remain full increasing the available liquids in PADD II above those that would otherwise be available from local supply.
July 2012
142 Canadian Energy Research Institute
The EIA dry gas production forecast for the Midwest is forecast to peak in 2011 at 9.65 bcf/d and decline for the remainder of the forecast period. Adding Alliance gas volumes increases peak supply to 11.25 bcf/d which then trends down at the same rate as the EIA PADD II dry gas supply forecast. Figure 3.43 provides that forecast.
Figure 3.43: PADD II Dry Gas Production plus Alliance Liquids Rich Gas Imports
Source: EIA AEO 2012 for dry gas production, CERI analysis
Ethane PADD II has an ethane based petrochemical industry that consumes in the order of 60 mb/d of ethane. At present a Midwest based ethane cracker would have a sizeable competitive advantage over a Gulf Coast cracker given growing ethane supply and the deep discount that Conway ethane trades in relation to Mont Belvieu.
A significant portion of the strategic advantage over Gulf Coast ethane crackers will dissipate once the incremental pipeline projects designed to relieve the Conway to Mont Belvieu congestion come into service in 2013 and 2014. While modest ethane demand growth is possible, significant growth in ethane requirements would require the construction of a new ethane cracker and associated petrochemical complex that would require in the order of 75 mb/d of product.
Although that quantity of supply is expected to be available over the long term, this forecast assumes such an investment is not made. New ethane cracking facilities are assumed built in the Gulf Coast rather than in the Midwest. Beginning in late 2013, with the completion of the Vantage pipeline, a portion of PADD II ethane supply will be exported to Canada. The forecast has 38 mb/d of ethane exported beginning in 2014, with some ramp up volumes in 2013. All remaining ethane surplus to local requirements and exports to Canada is assumed shipped to PADD III.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 143
Figure 3.44 provides the forecast for PADD II ethane supply demand balance. Ethane supply is forecast to peak in the range of 216 mb/d in 2019 coinciding with the point in time when North Dakota Bakken production is expected to plateau. Thereafter, available ethane volumes go into decline.
Over the forecast period in the order of 100 mb/d of ethane produced in PADD II is shipped from PADD II to PADD III to feed Gulf Coast petrochemical plants. This amount is in addition to any amount that is moved from PADD IV into PADD II for subsequent shipment to PADD III.
Figure 3.44: PADD II Ethane Supply and Demand Balance45
Source: Historical information from EIA AEO, CERI analysis
PADD II - Propane PADD II is a large seasonal propane consumer reflecting the use of propane in winter heating applications. Winter demand reaches as high as 650 mb/d while summer demand can be as low as 150 mb/d.
PADD II has sizeable propane storage capacity that is filled in the summer and emptied in the winter. In addition to storage draws in the winter, PADD II relies on transfers from PADD III and imports from Canada to fill winter peak demand. On a net basis PADD II has seen limited transfer to PADD III, but significant draws of propane in the winter. Figure 3.45 shows that the seasonal swing in demand is sufficient to cause PADD II to not only aggressively utilize its storage capacity but also increase imports from Canada in the winter.
45 Source: Historical Information EIA AEO 2012 ER
July 2012
144 Canadian Energy Research Institute
Recent supply growth in PADD II along with supply reductions of propane available from Canada have reduced the flow of propane imported into PADD II in the winter over the past two years. To forecast the PADD II supply, refinery production of propane/propylene was held constant for the remainder of the forecast period at 2011 levels. Gas plant production was derived in two parts, the first being the supply from the Bakken to which was added a forecast of available supply from the remainder of PADD II.
Figure 3.45: PADD II Monthly Propane Supply Demand History
Source: EIA Propane/ Propylene Supply and Disposition data
Propane production as part of the NGL stream produced from the Bakken increases by more than the declines in volumes associated with the remainder of PADD II until 2019 when Bakken production is assumed to plateau. Imports from Canada were assumed to continue declining throughout the forecast period. Propane demand has been weak for the last two years reflecting warmer than normal winters. The forecast assumes that 2013 demand returns to the last six year average and then escalates at 0.5 percent per year thereafter.
Transfers into PADD II are used to balance the available supply to market. It is assumed that the supply to balance the market will be drawn from PADD III.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 145
Figure 3.46: PADD II Propane/Propylene Supply and Demand
Source: CERI analysis
PADD III: Gulf Coast In addition to being the largest gas producing region in the US, PADD III, which includes Alabama, Arkansas, Louisiana, Mississippi, and New Mexico and Texas, is also the largest natural gas liquids consumer in the US.
PADD III is strongly connected by pipelines to both PADDs II and IV and has a good connection to PADD I. In addition to the large petrochemical complexes along the Gulf Coast in Texas and Louisiana that consume ethane and propane, the Mont Belvieu area also has a significant propane export capability that is forecast to grow substantially from some 165 mb/d to 450 mb/d by 2014.
The Gulf Coast demand for ethane/ethylene as a petrochemical feedstock is rising. Average PADD III consumption over the period 2005-2007 was 633 mb/d and has risen 38 percent to 872 mb/d in 2011.
That increase is in large part due to US ethane having become very competitive not only against domestic feedstock competitors such as propane and naphtha but also because its low price makes the US petrochemical industry cost-competitive worldwide.
Many facilities are either in the process of making or have already made the necessary investment to substitute more ethane into their feedstock mix which has increased the demand for ethane as shown in Figure 3.48. While additional ethane could be absorbed by existing facilities significant additional volume growth will require construction of new ethane crackers.
July 2012
146 Canadian Energy Research Institute
Investments in additional cracking capacity will only be made if the long term outlook for ethane supply is sufficiently robust at a projected low cost to support new petrochemical facilities over the long term.
Figure 3.47: US NGL Pipeline Map
Source: Hart Energy
A number of new ethane-based ethylene projects are under review including projects in the Marcellus as well as incremental Gulf Coast plants. The announced feasibility studies indicate that while the volume of ethane supply growth is uncertain the potential growth is large enough to support additional US ethane cracking capacity.46
46 Announced ethylene capacity include Sasol at 1-1.4 million tons, Dow at 1.7 million tons, Shell at 1 million tons, Chevron Philips Chemical at 1.5 million tons, Formosa at 0.8 million tons.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 147
Figure 3.48: PADD III Ethane/Ethylene Demand
Source: EIA data
Although a small volume of PADD III ethane/ethylene averaging 19 mb/d is supplied by refineries the majority is provided by gas plant production and transfers of ethane/ethylene from other US regions into PADD III.
Ethane/ethylene is not imported into the US. Gas plant production of ethane/ethylene in PADD III has increased 19 percent from an average of 471 mb/d in 2005-2007 to 562 mb/d in 2011. Transfers of ethane/ethylene into PADD III, primarily from PADD II have increased 106 percent from an average of 138 mb/d in 2005-2007 to 284 mb/d in 2011. This large increase reflects the combined impact of growing wet gas production and more cryogenic gas processing capability in PADDs II and IV.
Figure 3.49: PADD III Ethane/Ethylene Supply
Source: EIA data
July 2012
148 Canadian Energy Research Institute
PADD III propane use has recovered from lows reached during the trough of the recession. However, absolute levels in 2011 are down 5 percent from 2005-2007 averages.
Exports on the other hand, are rising, reflecting the impact in other regions of surplus supply increases on PADD III. Exports from PADD III averaged 110 mb/d in 2011 up from an average of 28 mb/d over the 2005 to 2007 period. Export capacity from PADD III from Mont Belvieu area is currently limited to approximately 165 mb/d, constrained by refrigeration capacity.
Refrigeration capacity is being expanded and is expected to reach 250 mb/d later in 2012 with further expansions to 450 mb/d by 2014.
Figure 3.50: PADD III Propane/Propylene Demand & Exports
Source: EIA data
Both local PADD III propane/propylene supply from refineries and gas plant production is marginally higher in 2011 than the 2005-2007 average, imports have shrunk from 57 mb/d to near zero reflecting the strength of supply growth in other regions that more than offset PADD III requirements.
During the 2005 to 2007 time period PADD III was a net supplier each month and on average supplied 96 mb/d to the remainder of the US. Amounts supplied increased in the winter to as much as 220 mb/d responding to winter heating requirements.
Beginning in the summer of 2009, PADD III received more volumes from other US regions than it supplied to other regions, while maintaining a deficit in the winter. By 2011 PADD III only transferred 36 mb/d to other US regions reflecting the continued growth in supplies from other US regions. The trend is shown in Figure 3.52.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 149
Figure 3.51: PADD III Propane/Propylene Production & Imports
Source: EIA data
Figure 3.52: Transfers of Propane/Propylene to PADD III from Other US Regions
Source: EIA data
As available supply continues to grow in other areas of the US, PADD III will grow as a net recipient of propane/propylene with any surplus to PADD III exported from Mont Belvieu.
July 2012
150 Canadian Energy Research Institute
For the purposes of this study CERI has matched the EIA’s Southwest and Gulf Coast supply regions with the PADD III demand region. The EIA is forecasting the combined Southwest and Gulf Coast dry gas production to ramp up to 27.7 bcf/d in 2012 and then fall off in 2013 and 2014 before slowly beginning to rise again in 2017. Overall gas supply in these regions is relatively stable.
Refinery ethane production is very small and has been assumed to remain constant at 2011 levels for the term of the forecast.
Converting gas supply to a forecast of available ethane revolves around assumptions regarding the amount of ethane available for recovery, the recovery rate, and since there are no exports, the PADD III demand for ethane.
Figure 3.53: EIA Southwest and Gulf Coast Region Gas Supply Forecast47
Source: EAI AEO ER 2012
Despite a relatively stable supply picture painted by the EIA in AEO 2012, CERI is forecasting rising NGL production. This increase occurs in response to current economic incentives to drill for and connect liquids rich gas in preference to dry gas. CERI forecasts that as a result of a richer gas stream being produced that ethane and propane available for extraction will increase in the order of 25 percent over the 2012 to 2018 period.
Ethane PADD III serves as a large supplier of ethane, a larger consumer, and the recipient of transfers from PADDs I, II, and IV.
47 Source: EIA AEO ER 2012
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 151
Since ethane is not exported and aside from some seasonal volume imbalances that can be smoothed out with available storage, the market for ethane must balance. This means that if available ethane supply exceeds the feedstock demand for ethane the market price for ethane must reduce to the point that it is more economical to burn the ethane by leaving it in the gas stream than removing it and transporting it to the Gulf Coast for utilization as feedstock.
Given the long lead times for construction of new ethane crackers (currently announced projects are projecting 2017 on stream dates), ethane prices will signal the need to have ethane remain in the gas stream. This means that the ethane netback must drop to the point where, on an energy basis, it is worth no more than the gas itself. Given the proximity of Texas and Louisiana’s gas production to Gulf Coast crackers it is most likely that ethane production in PADDs I and II will reduce to balance overall market requirements during times of surplus production while production continues in PADD III.
For the purposes of this forecast CERI has not adjusted supply by region and subsequent transfers to PADD III, but rather identifies the amount of ethane that will need to be either not removed from the gas stream (rejection) or re-injected if it has been removed.
In terms of new volumes available to be transferred into PADD III the largest increase is from PADD I which increases from zero volume today to as much as 136 mb/d in 2018 immediately preceding the assumed startup of a Marcellus region cracker. Available transfers to PADD III then drop off to accommodate supply for the new cracker in 2017 and begin to grow again reaching 152 mb/d by the end of the forecast period as shown in Figure 2.53. Combined PADDs II, IV and V volumes rise steadily to 340 mb/d by 2020 and roughly stabilize at that level for the remainder of the forecast.
Figure 3.54: Transfers of Ethane/Ethylene into PADD III
Source: CERI analysis
July 2012
152 Canadian Energy Research Institute
As demonstrated in Figure 3.55 even after allowing for incremental demand arising from announced and under construction cracking capacity additions through 2014 ethane supply exceeds expected demand, and will remain surplus to demand until recently announced new projects can be online sometime in 2017.
Excess supply begins to develop in 2012 and is in the range of 220 mb/d in 2016 indicating that ethane prices will be quite low across North America. Assuming announced ethane cracker projects are constructed as announced the market moves into relative balance in 2017.
Figure 3.55: PADD III Ethane Supply/Demand Forecast
Source: EIA historical data, CERI analysis
Propane/Propylene PADD III refinery production of propane/propylene amounts to some 349 mb/d. For the purposes of this forecast CERI assumes that production volume continues for the duration of the forecast. Gas plant production of propane will rise as liquids-rich gas makes up a larger portion of PADD III produced gas volumes. CERI is forecasting that gas plant propane production will increase from 365 mb/d in 2011 to 495,000 bbl per day by the end of the forecast. When combined, refinery and gas plant production will increase from 713 mb/d in 2011 to 843 mb/d by 2035 as shown in Figure 3.56.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 153
Figure 3.56: PADD III Propane/Propylene Supply and Demand
Source: EIA historical data, CERI analysis
Local demand is assumed to grow slowly from 567 mb/d in 2011 to 640 mb/d by 2035. Inter- regional transfers of propane to other PADD regions are comparatively small given the growing supplies across the US, so the burgeoning PADD III surplus of propane must be exported.
Exports are projected to grow from 110 mb/d in 2011 to a peak of 268 mb/d by 2019 and then gradually decline to 212 mb/d over the remainder of the forecast as supply stabilizes and slowly rising demand eats away at the available surplus.
Construction of incremental propane export capacity in Mont Belvieu is in progress with forecast capacity of 115 mb/d being added by year end 2012 and an additional 120 mb/d added in Q3 2013. The requirement to increase propane/propylene exports to almost triple 2011 amounts over the next few years will require that Mont Belvieu prices be sufficiently discounted to world market prices to absorb this quantity of incremental supply.
PADD IV: Rockies PADD IV encompasses the Rocky Mountain States of Colorado, Idaho, Montana, Utah, and Wyoming. Although this region is a small consumer of NGLs it is a significant producer that transfers much of its production to PADDs II and PADD III.
PADD IV ethane/ethylene demand is small and highly variable. Average requirements in 2005- 2008 amounted to 5,800 bbl/d and declined to an average of 1,100 bbl/d over the 2009 to 2011 period. Exports and refinery use were zero throughout the period.
July 2012
154 Canadian Energy Research Institute
Figure 3.57: PADD IV Ethane/Ethylene Demand
Source: EIA data
PADD IV ethane/ethylene supply is provided by gas plant production which has grown from an average of 84.8 mb/d in 2005-2007 to 178.5 mb/d in 2011. With limited local demand, substantially all of this supply is being transferred to other regions for consumption as shown in Figure 3.58.
Figure 3.58: PADD IV Ethane/Ethylene Supply
Source: EIA data
PADD IV propane/propylene demand, shown in Figure 3.59, is relatively small and seasonal averaging 38 mb/d over the 2005 to 2011 period. Winter peak demand can be as high as 66 mb/d as was the case in January 2008. Summer demand can fall below 20 mb/d. Both exports and refinery use are zero.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 155
Figure 3.59: PADD IV Propane/Propylene Demand
Source: EIA data
PADD IV refinery supply of propane/propylene, shown in Figure 3.60 has been relatively stable over the past six years averaging 8.8 mb/d, while gas plant supply has increased from an average of 56.8 mb/d over the 2005-2007 period to 90.7 mb/d in 2011.
Figure 3.60: PADD IV Propane/Propylene Supply Sources
Source: EIA data
PADD IV has a growing surplus of propane/propylene that it transfers into PADD III. That volume has increased from an average of 37.3 mb/d in the 2005-2007 period to 71 mb/d in 2011 as shown in Figure 3.61.
July 2012
156 Canadian Energy Research Institute
Figure 3.61: PADD IV Transfers of Propane/Propylene to PADD III
Source: EIA data
PADD V: West Coast PADD V encompasses the west coast states of Alaska, Arizona, California, Hawaii, Nevada, Oregon, and Washington.
PADD V has no ethane demand and a relatively small propane/propylene requirement. Propane/propylene demand is seasonal and ranges from 36 mb/d to 90 mb/d, with exports ranging from 5 mb/d to 32 mb/d. As shown in Figure 3.62, over the period 2005 to 2011, PADD V demand averaged 56.1 mb/d while exports averaged 10.2 mb/d.
Figure 3.62: PADD V Propane/Propylene Demand
Source: EIA data
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 157
PADD V also has no ethane supply and its propane/propylene supply is provided by a combination of refinery production (80 percent) and gas plant production (20 percent). Both refinery production and gas plant production are showing modest declines over the period 2005 to 2011. Total supply declined from 69.5 mb/d in 2005 to 58.7 mb/d in 2011. Propane imports averaged 2.9 b/d over the period 2005 to 2011.
Figure 3.63: PADD V Propane/Propylene Supply Sources
Source: EIA data
PADD IV and V Forecast The CERI forecast relies on the EIA AEO gas supply forecast to drive its gas plant liquids production forecast.
The EIA utilizes different regions in its gas supply model than in the presentation of liquids supply and demand volumes provided above. In addition, as compared with the forecast gas supply in PADD IV, forecast PADD V volumes are small. As a result, CERI believes it can produce a better alignment of historical gas supply and liquids production if PADDs IV and V are aggregated on the liquids side, and West Coast and Rocky Mountain States are aggregated for the gas supply forecast which then drives its gas plant liquids production forecast.
As shown in Figure 3.64, the EIA is forecasting that gas supply will shrink from recent levels of 14 bcf/d to 13.9 bcf/d in 2013 and then as gas prices rebound that gas supply will not only recover but grow to exceed 16 bcf/d by 2035.
CERI has applied the combination of an estimate of NGLs entrained in the gas stream and the recovery rate to estimate the available NGLs.
July 2012
158 Canadian Energy Research Institute
Figure 3.64: EIA AEO 2012 PADD IV and PADD V Gas Production Forecast48
Source: EAI AEO ER 2012
Combined PADD IV and V ethane production has grown from an average of 84.8 mb/d in 2005- 2007 to an average of 178.5 mb/d in 2011. CERI is forecasting that gas plant ethane/ethylene will continue to grow as more turbo expander facilities are built and as the industry pursues its liquids-rich gas strategy with ethane production reaching 200 mb/d in 2017 and continuing to increase with rising gas production to reach 224 mb/d by 2035.
Neither PADD IV nor PADD V currently has any meaningful local ethane/ethylene requirements. CERI is not forecasting that to change over the forecast period. As a result all gas plant ethane/ethylene production will be transferred to the Gulf Coast either directly, or via PADD II for use in Gulf Coast ethane crackers.
Figure 3.65: PADDs IV and V Ethane/Ethylene Production Forecast49
Source: EIA historical data, CERI analysis
48 Source: EIA AEO 2012 ER 49 Source History: EIA
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 159
Regarding propane/propylene, PADD’s IV and V are currently importing in the order of 11 mb/d. CERI is declining this volume in response to both weak supply in Canada and growing supply in the US.
Refinery supply of propane/propylene is currently about 56 mb/d. CERI has forecast that level of supply to continue for the remainder of the forecast period. Taking the same approach for gas plant production of propane/propylene as taken for ethane, CERI is forecasting that supply will rise along with the increase in gas supply from 101.8 mb/d in 2011 to 131 mb/d by 2035.
PADDs IV and V combined exports total 7 mb/d with all those volumes exported from PADD V. Local demand for propane/propylene only amounts to in the range of 92.7 mb/d and is assumed to grow at 0.25 percent per year for the term of the forecast.
Available supply is roughly double local demand which means that all excess volume needs to be transferred to PADDs II and III. For the purposes of this forecast all surplus volume is assumed to end up in PADD III where the ultimate lower-48 propane supply demand balance is determined and any surplus is exported from Mont Belvieu.
Propane/propylene transfers to PADD III amount to some 71.4 mb/d in 2011 rising to 84.7 mb/d by 2015 and 86.4 mb/d by 2035.
Figure 3.66: PADDs IV and V Propane/Propylene Supply and Demand Forecast50
Source: EIA historical data, CERI analysis
50 Ibid.
July 2012
160 Canadian Energy Research Institute
Summary and Conclusions US natural gas supply is transitioning from supply provided by conventional resources and coalbed methane (CBM) to a significant portion of total supply being provided from shale gas resources. Recently, some 38 percent of US gas production, i.e., 25 bcf/d of 65 bcf/d total dry gas production, was supplied from shale gas resources.
Although some of the shale gas supply is not liquids-rich, much of it is liquids-rich. While some liquids-rich gas supply has been added in conventional supply areas with already existing NGL infrastructure significant amounts of NGLs are being added in areas without sufficient NGL infrastructure. In those areas, the rate of liquids-rich gas supply addition is being throttled by the rate at which NGL infrastructure is being added.
While new gas wells can be added and brought on stream in a matter of weeks, midstream infrastructure can take from 12 to 36 months to plan, permit, and construct. Notable examples of infrastructure affecting NGL production rates include shale gas producing areas like the Marcellus and the Bakken.
The midstream business is playing catch-up to add sufficient gas processing plants, NGL pipelines and fractionation facilities to keep up with liquids-rich gas additions. Given midstream project lead times, this incremental capacity will continue to come online over the next 24 months providing increasing supplies of NGLs from already developed plays.
Particularly for the Bakken and Marcellus sourced supplies, CERI utilized estimates of facilities on-stream times to forecast ethane and propane supply availability.
To forecast available NGLs, CERI largely extended recent trends in refinery NGL supply and then forecast gas plant supply by applying NGL yields to forecasts of gas supply at a PADD level. CERI has undertaken more detailed modeling of natural gas supply in the emerging Bakken and Marcellus plays, and then relied extensively on EIA Annual Energy Outlook 2012 gas production forecast throughout the remainder of the US.
Additional supplies of ethane are forecast to be sufficiently high to warrant continued expansion of existing ethane cracking capacity and have sufficient longevity to support the construction of new ethane cracking facilities, while additional supplies of propane are sufficiently large to support additional propane based petrochemicals manufacturing and cause the US to become a significant net exporter of propane. Increased propane exports are, however, dependent on increased Mont Belvieu export facilities that are currently under construction.
PADD I historically produced little NGLs and was a large seasonal consumer of propane for use in heating. PADD I did not have an ethane based petrochemical business, and propane requirement to meet its heating load was largely imported or transferred from PADDs II and PADD III. Development of the Utica and Marcellus shale gas supplies places a large liquids-rich gas supply in the heart of this traditional market.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 161
Once fractionation and de-ethanization facilities are completed, PADD I will produce as much as 150 mb/d of ethane by 2015 growing to in excess of 250 mb/d which will support the Mariner West export pipeline to Canada and provide sufficient additional supply to support pipelines to move ethane to the Gulf Coast and at least one local world-scale ethane cracker, should such a facility be built. Meanwhile propane supply is estimated to increase to some 82 mb/d by 2015, with further increases to 143 mb/d over the forecast period. This supply can be absorbed in the local market, displacing imports and volumes historically transferred into the region from PADDs II and PADD III.
PADD II represents both a significant and growing NGL supply from the Bakken, and demand in its Conway area, that serves as a regional hub for NGL pipelines and fractionation facilities. Additionally, PADD II is home to the Aux Sable Channahon facility that extracts NGLs from the Alliance Pipeline gas stream that is mainly imported from Canada. Once required gas plants, de- ethanization facilities and NGL pipelines are constructed, the Bakken is expected to make available 40 mb/d of ethane in 2014 increasing to 85 mb/d by 2020. Of that total supply, approximately 38 mb/d will be exported to Canada via the Vantage Pipeline. The remainder will be moved via a combination of OneOk’s y-grade pipeline to Overland Pass Pipeline and then to Bushton, KS, and as wet gas via Alliance Pipeline to Channahon, IL.
PADD II ethane supply is projected to grow from 160 mb/d to 216 mb/d as associated gas from the Bakken oil production continues to grow and then begin a slow decline. Local demand is only forecast to grow marginally with surplus supply transferred to PADD III.
PADD II is a large market for propane with winter heating demand peaking in the range of 600 mb/d while summer lows fall below 200 mb/d averaging approximately 300 mb/d. PADD II supply is just over 250 mb/d increasing to 277 mb/d by 2019. PADD II is net long in the summers and short in the winter. A combination of imports from Canada and transfers from PADD IV along with seasonal transfers to and from PADD III are required to seasonally balance the market.
At this time, the increased PADD II supply plus transfers received from PADD IV exceed available pipeline capacity from PADD II to the Gulf Coast. Until pipeline expansions currently under development are complete, the Conway area is facing a supply glut with heavily discounted ethane and propane prices when compared with Mont Belvieu. Pricing pressures are expected to ease by 2014 after completion of the various pipeline developments.
PADD III is both a large market and a large source of NGL supply. It is well connected by pipeline with each of PADDs I, II, and IV. A number of additional NGL pipeline projects are either under construction or in advanced planning stages. That will, by early 2014 increase the available supply of NGLs to the Gulf Coast and its petrochemical industry and the propane export facilities in Mont Belvieu.
July 2012
162 Canadian Energy Research Institute
PADD III ethane supply has expanded by 197 mb/d over the last five years to total 872mb/d in 2011. That increased supply has been absorbed by preferentially cracking ethane over heavier hydrocarbons and retrofitting of heavier hydrocarbon crackers to run on ethane. The combination of transfers of excess ethane from PADDs I, II, and IV along with growth in local supply are expected to increase total available supply to 1,145 mb/d by 2017 representing a 256 mb/d increase in available ethane.
A number of new ethane crackers are currently planned and under construction in the area. Given the long project lead-times required for planning, permitting, and construction, these incremental facilities will not be able to absorb that additional available supply before 2017. In the meantime, surplus ethane has depressed prices to the point that ethane is being re-injected to reduce supply to meet available demand. Ethane prices are expected to recover as this incremental cracking capacity comes on line.
PADD III propane/propylene supply has also moved into a surplus situation. While propane/propylene demand is roughly stable over the past five years, propane/propylene supply has increased. In response, imports are being reduced and exports are increasing. Propane exports have increased from 32 mb/d in 2007 to 110 mb/d by 2011, while imports declined 35 mb/d over that same period. In more recent months exports have increased to the range of 160 mb/d, which is at or near physical export capacity.
Construction of incremental propane export capacity in Mont Belvieu is in progress with forecast capacity of 115 mb/d being added by year end 2012 and an additional 120 mb/d added in Q3 2013. This incremental export capacity is required to market the growing supply of PADD III propane.
PADD IV has a very limited ethane market amounting to some 1.1 mb/d. Its ethane supply is robust and growing, having increased 97 mb/d to 179 mb/d over the past five years. As there is no local market, all that ethane is transferred by pipeline to PADDs II and III.
The PADD IV propane market averages about 38 mb/d and it is seasonal, reflecting local heating load. Supply, including imports, averages 90 mb/d with the surplus volumes transferred to PADDs II and III.
PADD V’s ethane market is non-existent, while the propane market is approximately 56 mb/d in size and is roughly balanced on an annual basis. Exports provide the balancing mechanism.
For forecasting purposes PADDs IV and V were combined. The forecast ethane supply for PADDs IV and V combined slowly increases from 180 mb/d in 2012 to 224 mb/d over the forecast period. There is insignificant local ethane demand so the increased volume is transferred to PADDs II and III.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 163
Regarding PADDs IV and V propane, production is forecast to increase slowly from 170 mb/d in 2012 to 185 mb/d over the forecast period while local demand is growing slowly from a base of 77 mb/d. Any surplus propane is transferred to PADDs II and III.
July 2012
164 Canadian Energy Research Institute
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 165
Appendix A: Petroleum Administration for Defense Districts (PADD Districts) and Related States
US data for petroleum products is regularly aggregated to five main regions and represented in the map below. This study has used the same regions for its analysis.
Figure A.1: PADD Districts
Source: EIA
PADD I (East Coast) is composed of the following three sub-districts:
• Sub-district A (New England): Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont. • Sub-district B (Central Atlantic): Delaware, District of Columbia, Maryland, New Jersey, New York, and Pennsylvania. • Sub-district C (Lower Atlantic): Florida, Georgia, North Carolina, South Carolina, Virginia, and West Virginia.
PADD II (Midwest): Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, South Dakota, Ohio, Oklahoma, Tennessee, and Wisconsin.
PADD III (Gulf Coast): Alabama, Arkansas, Louisiana, Mississippi, and New Mexico, and Texas.
PADD IV (Rocky Mountain): Colorado, Idaho, Montana, Utah, and Wyoming.
PADD V (West Coast): Alaska, Arizona, California, Hawaii, Nevada, Oregon, and Washington.
July 2012
166 Canadian Energy Research Institute
Regions used in the EIA’s Gas Supply model vary from the regions defined for liquids reporting purposes.
Figure A.2: Oil and Gas Supply Model Regions
Source: EIA
Handling of the differences between the states in PADDs vs States in EIA’s supply model:
EIA uses PADD aggregation areas for its NGL volume reporting and uses Oil and Gas Supply model regions in presenting its forecast of AEO gas supply volumes to 2035.
In the process of building out its NGL forecast, CERI has chosen to map the Northeast supply region gas volumes against PADD I NGL volumes, Midwest against PADD II, sum of Southwest and Gulf Coast against PADD III, Rockies against PADD IV and West Coast against PADD V.
In doing so, some obvious mismatches occur. North Dakota which is forecast to become a big liquids producer is in the EIA Midwest supply region which is mapped to PADD II, while its gas production is forecast by the EIA as PADD IV supply. Similarly, Ohio with its potential to add significant gas plant liquids supply is in the North East supply zone while its liquids are accounted for in PADD II.
The CERI forecast is constructed off the EIA AEO 2012 early release, which does not provide state by state gas supply breakdowns and cannot be easily reconstructed at the PADD level of aggregation. Fortunately, expanding NGL infrastructure continues to build stronger connections between PADD I and PADD III, and between PADD IV and PADD II, where imbalances are cleared to PADD III through expanded connectivity between Conway and Mont Belvieu as seen in Figure A.3.
As a result the study has chosen to clear regional supply imbalances by transferring them to PADD III and then reporting the ultimate supply demand balances as volumes available for import or export from PADD III.
July 2012 Natural Gas Liquids in North America: Overview and Outlook to 2035 167
Appendix B: Natural Gas Liquids Infrastructure in the United States
Figure B.1: Gas Processing Capacity in the United States
Source: National Petroleum Council
Figure B.2: Major NGL Hubs and Transportation Corridors
Source National Petroleum Council
July 2012
168 Canadian Energy Research Institute
Figure B.3: New & Repurposed NGL Pipeline Systems
Source: Oil & Gas Journal
Figure B.4: NGLs Content by Basin in the United States
Source: National Petroleum Council
July 2012